Ohio Power (OHIPN) 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2017USD ($)shares
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float | $	$ 34,179,628,893
Entity Common Stock, Shares Outstanding	492,005,598
AEP Texas Inc. [Member]
Entity Registrant Name	AEP Texas Inc.
Entity Central Index Key	1,721,781
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	100
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	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Vertically Integrated Utilities	$ 9,095.1	$ 9,012.4	$ 9,069.9
Transmission and Distribution Utilities	4,328.9	4,328.3	4,392
Generation and Marketing Revenues	1,771.4	2,858.7	2,866.7
Sales to AEP Affiliates	0	0	0
Other Revenues	229.5	180.7	124.6
TOTAL REVENUES	15,424.9	16,380.1	16,453.2
Expenses
Fuel and Other Consumables Used for Electric Generation	2,346.5	2,908.9	3,348.1
Purchased Electricity for Resale	2,965.3	2,821.4	2,760.1
Other Operation	2,484	2,956.9	2,703.9
Maintenance	1,141.3	1,237.7	1,325.3
Asset Impairments and Other Related Charges	87.1	2,267.8	0
Gain on Sale of Merchant Generation Assets	(226.4)	0	0
Depreciation and Amortization	1,997.2	1,962.3	2,009.7
Taxes Other Than Income Taxes	1,059.4	1,018	972.6
TOTAL EXPENSES	11,854.4	15,173	13,119.7
OPERATING INCOME (LOSS)	3,570.5	1,207.1	3,333.5
Other Income (Expense):
Interest and Investment Income	16	16.3	7.9
Carrying Costs Income	18.6	16.2	23.5
Allowance for Equity Funds Used During Construction	93.7	113.2	131.9
Gain on Sale of Equity Investment	12.4	0	0
Interest Expense	(895)	(877.2)	(873.9)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	2,816.2	475.6	2,622.9
Income Tax Expense (Credit)	969.7	(73.7)	919.6
Equity Earnings (Loss) of Unconsolidated Subsidiaries	82.4	71.2	65.3
Income (Loss) from Continuing Operations	1,928.9	620.5	1,768.6
Income (Loss) from Discontinued Operations, Net of Tax	0	(2.5)	283.7
NET INCOME (LOSS)	1,928.9	618	2,052.3
Net Income Attributable to Noncontrolling Interests	16.3	7.1	5.2
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 1,912.6	$ 610.9	$ 2,047.1
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	491,814,651	491,495,458	490,340,522
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$ 3.89	$ 1.25	$ 3.59
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	0	(0.01)	0.58
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 3.89	$ 1.24	$ 4.17
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	492,611,067	491,662,007	490,574,568
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$ 3.88	$ 1.25	$ 3.59
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	0	(0.01)	0.58
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 3.88	$ 1.24	$ 4.17
AEP Texas Inc. [Member]
Revenues
Transmission and Distribution Utilities	$ 1,470.3	$ 1,383.2	$ 1,374.1
Sales to AEP Affiliates	65.7	75.7	78.5
Other Revenues	2.4	2.5	5.4
TOTAL REVENUES	1,538.4	1,461.4	1,458
Expenses
Fuel and Other Consumables Used for Electric Generation	20.9	32.1	32.1
Other Operation	449.5	454.5	439.9
Maintenance	75.9	73.7	91
Asset Impairments and Other Related Charges		72.7	0
Depreciation and Amortization	450.1	413.9	468.9
Taxes Other Than Income Taxes	122.3	107.6	105.3
TOTAL EXPENSES	1,118.7	1,081.8	1,137.2
OPERATING INCOME (LOSS)	419.7	379.6	320.8
Other Income (Expense):
Interest Income	2.9	10.9	0.8
Allowance for Equity Funds Used During Construction	6.8	9.2	6.7
Interest Expense	(142.3)	(144.4)	(148.4)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	287.1	255.3	179.9
Income Tax Expense (Credit)	(23.4)	59.9	58.2
Income (Loss) from Continuing Operations	310.5	195.4	121.7
Income (Loss) from Discontinued Operations, Net of Tax	0	(48.8)	(1.4)
NET INCOME (LOSS)	310.5	146.6	120.3
AEP Transmission Co [Member]
Revenues
Electrical Transmission Revenue	141.9	110.4	84.3
Sales to AEP Affiliates	580.5	367.5	225.6
Other Revenues	0.8	0.1	0.3
TOTAL REVENUES	723.2	478	310.2
Expenses
Other Operation	60.1	37	22.4
Maintenance	8.5	6.7	5
Depreciation and Amortization	97.1	65.9	42.4
Taxes Other Than Income Taxes	109.7	88.3	66
TOTAL EXPENSES	275.4	197.9	135.8
OPERATING INCOME (LOSS)	447.8	280.1	174.4
Other Income (Expense):
Interest Income	1.2	0.4	0.1
Allowance for Equity Funds Used During Construction	52.3	52.3	53
Interest Expense	(68)	(46)	(34.6)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	433.3	286.8	192.9
Income Tax Expense (Credit)	147.2	94.1	60
NET INCOME (LOSS)	286.1	192.7	132.9
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	2,749	2,847.4	2,805.6
Sales to AEP Affiliates	172	142.1	147.8
Other Revenues	13.2	11.7	10.1
TOTAL REVENUES	2,934.2	3,001.2	2,963.5
Expenses
Fuel and Other Consumables Used for Electric Generation	597.3	654.9	675.9
Purchased Electricity for Resale	357.6	329.3	395.2
Other Operation	497.9	486.7	405.4
Maintenance	251.6	275	263.3
Depreciation and Amortization	407.9	388.5	388.8
Taxes Other Than Income Taxes	126.4	123.5	124.1
TOTAL EXPENSES	2,238.7	2,257.9	2,252.7
OPERATING INCOME (LOSS)	695.5	743.3	710.8
Other Income (Expense):
Interest Income	1.4	1.3	1.4
Carrying Costs Income	1.4	0.4	1.2
Allowance for Equity Funds Used During Construction	9.2	11.7	13.8
Interest Expense	(190.9)	(188.5)	(192.3)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	516.6	568.2	534.9
Income Tax Expense (Credit)	185.3	199.1	194.3
NET INCOME (LOSS)	331.3	369.1	340.6
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	2,042.5	2,062.3	2,073.3
Sales to AEP Affiliates	1.8	26.2	27.4
Other Revenues - Affiliated	62.6	62.1	78.8
Other Revenues	14.3	17	6.7
TOTAL REVENUES	2,121.2	2,167.6	2,186.2
Expenses
Fuel and Other Consumables Used for Electric Generation	295.1	284.1	336.3
Purchased Electricity for Resale	152.2	198.7	195.8
Purchased Electricity from AEP Affiliates	223.9	228.6	232.1
Other Operation	585.2	572	553.4
Maintenance	208.4	205.6	212
Asset Impairments and Other Related Charges	0	10.5	0
Depreciation and Amortization	210.9	191.7	198.4
Taxes Other Than Income Taxes	92.2	94.8	88.3
TOTAL EXPENSES	1,767.9	1,786	1,816.3
OPERATING INCOME (LOSS)	353.3	381.6	369.9
Other Income (Expense):
Interest Income	1.8	1.2	1.3
Carrying Costs Income	12.7	10.1	8.3
Allowance for Equity Funds Used During Construction	11.1	15.3	11.6
Interest Expense	(110.8)	(100.8)	(90.2)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	268.1	307.4	300.9
Income Tax Expense (Credit)	81.4	67.5	96.1
NET INCOME (LOSS)	186.7	239.9	204.8
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	2,853.5	2,930.1	3,056.1
Sales to AEP Affiliates	24.4	17.3	84.1
Other Revenues	6	6.5	8.5
TOTAL REVENUES	2,883.9	2,953.9	3,148.7
Expenses
Purchased Electricity for Resale	705.9	663.1	635
Purchased Electricity from AEP Affiliates	108.5	141.9	527.1
Generation Deferrals	0	(82.7)	(30.7)
Amortization of Generation Deferrals	229.2	242.9	169.1
Other Operation	511.5	706.8	630.3
Maintenance	141.2	148	166.8
Depreciation and Amortization	225.9	238.6	217.5
Taxes Other Than Income Taxes	391.5	386.8	372.8
TOTAL EXPENSES	2,313.7	2,445.4	2,687.9
OPERATING INCOME (LOSS)	570.2	508.5	460.8
Other Income (Expense):
Interest Income	4.9	3.8	5.6
Carrying Costs Income	3.6	19.9	11.8
Allowance for Equity Funds Used During Construction	6.4	6	8.8
Interest Expense	(101.9)	(112.2)	(127.8)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	483.2	426	359.2
Income Tax Expense (Credit)	159.3	143.8	126.5
NET INCOME (LOSS)	323.9	282.2	232.7
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	1,417.5	1,242.8	1,331.4
Sales to AEP Affiliates	4.3	2.6	4.6
Other Revenues	5.4	4.4	3.2
TOTAL REVENUES	1,427.2	1,249.8	1,339.2
Expenses
Fuel and Other Consumables Used for Electric Generation	134.5	44.8	301.4
Purchased Electricity for Resale	514.9	441.2	316.9
Purchased Electricity from AEP Affiliates	0	3.7	0
Other Operation	311.7	288.5	268.4
Maintenance	120.3	106.9	104.6
Depreciation and Amortization	130.4	130.2	117.5
Taxes Other Than Income Taxes	40.5	35.8	37.2
TOTAL EXPENSES	1,252.3	1,051.1	1,146
OPERATING INCOME (LOSS)	174.9	198.7	193.2
Other Income (Expense):
Interest Income	0.1	0.7	0.4
Allowance for Equity Funds Used During Construction	0.5	6.2	8.8
Interest Expense	(53.4)	(51.2)	(58.6)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	122.1	154.4	143.8
Income Tax Expense (Credit)	50.1	54.4	51.3
NET INCOME (LOSS)	72	100	92.5
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	1,752.1	1,721.5	1,762.3
Sales to AEP Affiliates	25.9	24.5	16.6
Other Revenues	1.9	2	2
TOTAL REVENUES	1,779.9	1,748	1,780.9
Expenses
Fuel and Other Consumables Used for Electric Generation	496.1	517.8	570.6
Purchased Electricity for Resale	168.7	142.4	110.6
Other Operation	314.6	331.7	294.5
Maintenance	143.5	149.7	155.9
Asset Impairments and Other Related Charges	33.6	0	0
Depreciation and Amortization	217.4	196.5	192
Taxes Other Than Income Taxes	98.3	88.8	88.1
TOTAL EXPENSES	1,472.2	1,426.9	1,411.7
OPERATING INCOME (LOSS)	307.7	321.1	369.2
Other Income (Expense):
Interest Income	2.7	1.5	1.2
Allowance for Equity Funds Used During Construction	2.4	11	26.4
Interest Expense	(123.4)	(119.7)	(119.9)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	189.4	213.9	276.9
Income Tax Expense (Credit)	48.1	52.1	84.8
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(3.8)	7.9	3.9
NET INCOME (LOSS)	137.5	169.7	196
Net Income Attributable to Noncontrolling Interests	12.8	4.1	3.7
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 124.7	$ 165.6	$ 192.3

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Income (Loss)	$ 1,928.9	$ 618	$ 2,052.3
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(2.6)	(16.4)	(4.9)
Securities Available for Sale, Net of Tax	3.5	1.3	(0.6)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	1.1	0.6	1.2
Pension and OPEB Funded Status, Net of Tax	86.5	(14.7)	(25.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	88.5	(29.2)	(30)
TOTAL COMPREHENSIVE INCOME (LOSS)	2,017.4	588.8	2,022.3
Total Comprehensive Income Attributable to Noncontrolling Interest	16.3	7.1	5.2
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	2,001.1	581.7	2,017.1
AEP Texas Inc. [Member]
Net Income (Loss)	310.5	146.6	120.3
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.9	1.1	1.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.3	0.3	0.3
Pension and OPEB Funded Status, Net of Tax	1.1	0.9	0.2
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	2.3	2.3	1.7
TOTAL COMPREHENSIVE INCOME (LOSS)	312.8	148.9	122
AEP Transmission Co [Member]
Net Income (Loss)	286.1	192.7	132.9
Appalachian Power Co [Member]
Net Income (Loss)	331.3	369.1	340.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.7)	(0.7)	(0.3)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1.2)	(1.4)	(1.8)
Pension and OPEB Funded Status, Net of Tax	11.6	(3.5)	(5.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	9.7	(5.6)	(7.8)
TOTAL COMPREHENSIVE INCOME (LOSS)	341	363.5	332.8
Indiana Michigan Power Co [Member]
Net Income (Loss)	186.7	239.9	204.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.3	1.3	1.1
Pension and OPEB Funded Status, Net of Tax	2.8	(0.8)	(3.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	4.1	0.5	(2.4)
TOTAL COMPREHENSIVE INCOME (LOSS)	190.8	240.4	202.4
Ohio Power Co [Member]
Net Income (Loss)	323.9	282.2	232.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(1.1)	(1.3)	(1.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1.1)	(1.3)	(1.3)
TOTAL COMPREHENSIVE INCOME (LOSS)	322.8	280.9	231.4
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	72	100	92.5
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.8)	(0.8)	(0.8)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.8)	(0.8)	(0.8)
TOTAL COMPREHENSIVE INCOME (LOSS)	71.2	99.2	91.7
Southwestern Electric Power Co [Member]
Net Income (Loss)	137.5	169.7	196
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.4	1.7	2
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.7)	(0.7)	(1)
Pension and OPEB Funded Status, Net of Tax	4.7	(1)	(2.9)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	5.4	0	(1.9)
TOTAL COMPREHENSIVE INCOME (LOSS)	142.9	169.7	194.1
Total Comprehensive Income Attributable to Noncontrolling Interest	12.8	4.1	3.7
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	$ 130.1	$ 165.6	$ 190.4

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flow Hedges, Tax	$ (1.4)	$ (8.8)	$ (2.6)
Securities Available for Sale, Tax	1.9	0.7	(0.3)
Amortization of Pension and OPEB Deferred Costs, Tax	0.6	0.3	0.6
Pension and OPEB Funded Status, Tax	46.7	(7.9)	(13.9)
AEP Texas Inc. [Member]
Cash Flow Hedges, Tax	0.5	0.6	0.6
Amortization of Pension and OPEB Deferred Costs, Tax	0.1	0.2	0.2
Pension and OPEB Funded Status, Tax	0.6	0.5	0.1
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.4)	(0.4)	(0.1)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.6)	(0.8)	(1)
Pension and OPEB Funded Status, Tax	6.3	(1.9)	(3.1)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.7	0.7	0.6
Pension and OPEB Funded Status, Tax	1.5	(0.4)	(1.9)
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.6)	(0.7)	(0.7)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.4)	(0.4)	(0.4)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.8	0.9	1.1
Amortization of Pension and OPEB Deferred Costs, Tax	(0.4)	(0.4)	(0.5)
Pension and OPEB Funded Status, Tax	$ 2.5	$ (0.5)	$ (1.6)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	AEP Texas Inc. [Member]	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 Texas Inc. [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 Texas Inc. [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]AEP Texas Inc. [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]
TOTAL MEMBER'S EQUITY			$ 1,141														$ 964									$ 177
Common Stock, Dividends, Per Share, Declared	$ 2.15
Beginning Balance at Dec. 31, 2014	$ 16,824.5	$ 1,309.4		$ 3,366.9	$ 1,954	$ 1,980.2	$ 1,028.2	$ 2,097.2	$ 3,313.3	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,203.4	$ 532.6		$ 1,809.6	$ 980.9	$ 838.8	$ 364	$ 674.6	$ 7,406.6		$ 795.7		$ 1,291.9	$ 930.8	$ 814.6	$ 502	$ 1,294	$ (103.1)	$ (18.9)	$ 5	$ (14.3)	$ 5.6	$ 5	$ (7.5)	$ 4.3	$ 0.4
Beginning Balance, Shares at Dec. 31, 2014	509,739,159								509,700,000
Issuance of Common Stock, Value	$ 81.6								$ 10.7						70.9
Issuance of Common Stock, Shares	1,650,014								1,700,000
Capital Contributions from Member		272.3	279													272.3	279
Common Stock Dividends	$ (1,059)	(29)																					(1,055.4)	[1]	(29)
Common Stock Dividends				(243.8)	(120)	(225)		(120)																			(243.8)	(120)	(225)		(120)
Common Stock Dividends								(3.6)																															(3.6)	(3.6)
Stockholders' Equity, Other	29.5														22.2																								7.3
Net Income (Loss)		120.3																					2,047.1		120.3						192.3
Net Income (Loss) Attributable to Noncontrolling Interests	5.2							3.7																															5.2	3.7
Net Income (Loss)	2,052.3	120.3	132.9	340.6	204.8	232.7	92.5	196																		132.9	340.6	204.8	232.7	92.5
Other Comprehensive Income (Loss)	(30)	1.7		(7.8)	(2.4)	(1.3)	(0.8)	(1.9)																								(30)	1.7	(7.8)	(2.4)	(1.3)	(0.8)	(1.9)
Pension and OPEB Adjustment Related to Mitchell Plant	6																															6
Distribution of CSW Energy, Inc to Parent		0
Contribution of Amos Plant from Parent				19.1														19.1
Contribution of Mutual Energy SWEPCo, LLC from Parent								2														2
Ending Balance at Dec. 31, 2015	$ 17,904.9	1,674.7		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	804.9		1,828.7	980.9	838.8	364	676.6	8,398.3		887		1,388.7	1,015.6	822.3	594.5	1,366.3	(127.1)	(17.2)	(2.8)	(16.7)	4.3	4.2	(9.4)	13.2	0.5
Ending Balance, Shares at Dec. 31, 2015	511,389,173								511,400,000
TOTAL MEMBER'S EQUITY			1,552.9														1,243									309.9
Common Stock, Dividends, Per Share, Declared	$ 2.27
Issuance of Common Stock, Value	$ 34.2								$ 4.3						29.9
Issuance of Common Stock, Shares	659,347								600,000
Capital Contributions from Member		53	212													53	212
Common Stock Dividends	$ (1,121)	(34)																					(1,116.8)	[1]	(34)
Common Stock Dividends				(255)	(125)	(150)	(5)	(120)																			(255)	(125)	(150)	(5)	(120)
Common Stock Dividends								(4.2)																															(4.2)	(4.2)
Stockholders' Equity, Other	13.2														6.2																								7
Net Income (Loss)		146.6																					610.9		146.6						165.6
Net Income (Loss) Attributable to Noncontrolling Interests	7.1							4.1																															7.1	4.1
Net Income (Loss)	618	146.6	192.7	369.1	239.9	282.2	100	169.7																		192.7	369.1	239.9	282.2	100
Other Comprehensive Income (Loss)	(29.2)	2.3		(5.6)	0.5	(1.3)	(0.8)	0																								(29.2)	2.3	(5.6)	0.5	(1.3)	(0.8)
Distribution of CSW Energy, Inc to Parent		(185.5)																							(185.5)
Contribution of Amos Plant from Parent				0
Contribution of Mutual Energy SWEPCo, LLC from Parent								0
Ending Balance at Dec. 31, 2016	$ 17,420.1	1,657.1		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	857.9		1,828.7	980.9	838.8	364	676.6	7,892.4		814.1		1,502.8	1,130.5	954.5	689.5	1,411.9	(156.3)	(14.9)	(8.4)	(16.2)	3	3.4	(9.4)	23.1	0.4
Ending Balance, Shares at Dec. 31, 2016	512,048,520						10,482,000		512,000,000
TOTAL MEMBER'S EQUITY			1,957.6														1,455									502.6
Common Stock, Dividends, Per Share, Declared	$ 2.39
Issuance of Common Stock, Value	$ 12.2								$ 1.1						11.1
Issuance of Common Stock, Shares	162,124								200,000
Capital Contributions from Member		200	361.6													200	361.6
Common Stock Dividends	$ (1,191.9)																						(1,178.3)	[1]
Common Stock Dividends				(120)	(125)	(130)	$ (70)	(110)																			(120)	(125)	(130)	(70)	(110)
Common Stock Dividends								(13.6)																															(13.6)	(13.6)
Stockholders' Equity, Other	55.8														55																								0.8
Net Income (Loss)		310.5																					1,912.6		310.5						124.7
Net Income (Loss) Attributable to Noncontrolling Interests	16.3							12.8																															16.3	12.8
Net Income (Loss)	1,928.9	310.5	286.1	331.3	186.7	323.9	72	137.5																		286.1	331.3	186.7	323.9	72
Other Comprehensive Income (Loss)	88.5	2.3		9.7	4.1	(1.1)	(0.8)	5.4																								88.5	2.3	9.7	4.1	(1.1)	(0.8)	5.4
Distribution of CSW Energy, Inc to Parent		0
Contribution of Amos Plant from Parent				0
Contribution of Mutual Energy SWEPCo, LLC from Parent								0
Ending Balance at Dec. 31, 2017	$ 18,313.6	$ 2,169.9		$ 3,804.5	$ 2,217.6	$ 2,310.3	$ 1,215.3	$ 2,234.5	$ 3,329.4	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,398.7	$ 1,057.9		$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 8,626.7		$ 1,124.6		$ 1,714.1	$ 1,192.2	$ 1,148.4	$ 691.5	$ 1,426.6	$ (67.8)	$ (12.6)	$ 1.3	$ (12.1)	$ 1.9	$ 2.6	$ (4)	$ 26.6	$ (0.4)
Ending Balance, Shares at Dec. 31, 2017	512,210,644						10,482,000		512,200,000
TOTAL MEMBER'S EQUITY			$ 2,605.3														$ 1,816.6									$ 788.7
[1]	(a)Cash dividends declared per AEP common share were $2.39, $2.27 and $2.15 for the years ended December 31, 2017, 2016 and 2015, respectively.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents		$ 214.6	$ 210.5
Restricted Cash		198	193
Other Temporary Investments		161.7	138.7
Accounts Receivable:
Customers		643.9	705.1
Accrued Unbilled Revenues		230.2	158.7
Pledged Accounts Receivable - AEP Credit		954.2	972.7
Miscellaneous		101.2	118.1
Allowance for Uncollectible Accounts		(38.5)	(37.9)
Total Accounts Receivable		1,891	1,916.7
Fuel		387.7	423.8
Materials and Supplies		565.5	543.5
Risk Management Assets		126.2	94.5
Regulatory Asset for Under-Recovered Fuel Costs		292.5	156.6
Margin Deposits		105.5	79.9
Assets Held for Sale		0	1,951.2
Prepayments and Other Current Assets		310.4	325.5
TOTAL CURRENT ASSETS		4,253.1	6,033.9
Property, Plant and Equipment
Generation		20,760.5	19,848.9
Transmission		18,972.5	16,658.7
Distribution		19,868.5	18,900.8
Other Property, Plant and Equipment		3,706.3	3,444.3
Construction Work in Progress		4,120.7	3,183.9
Total Property, Plant and Equipment		67,428.5	62,036.6
Accumulated Depreciation and Amortization		17,167	16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		50,261.5	45,639.3	[1]
Other Noncurrent Assets
Regulatory Assets		3,587.6	5,625.5
Securitized Assets		1,211.2	1,486.1
Spent Nuclear Fuel and Decommissioning Trusts		2,527.6	2,256.2
Goodwill		52.5	52.5
Long-term Risk Management Assets		282.1	289.1
Deferred Charges and Other Noncurrent Assets		2,553.5	2,085.1
TOTAL OTHER NONCURRENT ASSETS		10,214.5	11,794.5
TOTAL ASSETS		64,729.1	63,467.7
Current Liabilities
Accounts Payable		2,065.3	1,688.5
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[2]	718	673
Other Short-term Debt		920.6	1,040
Total Short-term Debt		1,638.6	1,713
Long-term Debt Due Within One Year		1,753.7	2,878
Risk Management Liabilities		61.6	53.4
Customer Deposits		357	343.2
Accrued Taxes		1,115.5	1,048
Accrued Interest		234.5	227.2
Obligations Under Capital Leases		59	63.4
Regulatory Liability for Over-Recovered Fuel Costs		11.9	8
Liabilities Held for Sale		0	235.9
Other Current Liabilities		1,033.2	1,302.8
TOTAL CURRENT LIABILITIES		8,271.3	9,498
Noncurrent Liabilities
Long-term Debt		19,419.6	17,378.4
Long-term Debt - Affiliated		0	0
Long-term Risk Management Liabilities		322	316.2
Deferred Income Taxes		6,813.9	11,884.4
Regulatory Liabilities and Deferred Investment Tax Credits		8,422.3	3,751.3
Asset Retirement Obligations		1,925.5	1,830.6
Employee Benefits and Pension Obligations		398.1	614.1
Obligations Under Capital Leases		238.8	242.1
Deferred Credits and Other Noncurrent Liabilities		830.9	774.6
TOTAL NONCURRENT LIABILITIES		38,132.3	36,549.6
TOTAL LIABILITIES		46,403.6	46,047.6
Rate Matters
Commitments and Contingencies
Mezzanine Equity		11.9	0
Equity
Common Stock		3,329.4	3,328.3
Paid-in Capital		6,398.7	6,332.6
Retained Earnings		8,626.7	7,892.4
Accumulated Other Comprehensive Income (Loss)		(67.8)	(156.3)
TOTAL COMMON SHAREHOLDERS' EQUITY		18,287	17,397
Noncontrolling Interests		26.6	23.1
TOTAL EQUITY		18,313.6	17,420.1
TOTAL LIABILITIES AND EQUITY		64,729.1	63,467.7
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents		2	0.6
Restricted Cash		155.2	146.3
Advances to Affiliates		111.9	8.6
Accounts Receivable:
Customers		105.3	94.4
Affiliated Companies		12.3	11.8
Accrued Unbilled Revenues		75.8	64.8
Miscellaneous		1.3	0.1
Allowance for Uncollectible Accounts		(0.7)	(0.6)
Total Accounts Receivable		194	170.5
Fuel		3.6	9.8
Materials and Supplies		52	49
Risk Management Assets		0.5	0.2
Accrued Tax Benefits		41	0.7
Prepayments and Other Current Assets		3.6	3.5
TOTAL CURRENT ASSETS		563.8	389.2
Property, Plant and Equipment
Generation		350.7	349.6
Transmission		3,053.6	2,623.6
Distribution		3,718.6	3,527.2
Other Property, Plant and Equipment		461	436.4
Construction Work in Progress		835.7	385.9
Total Property, Plant and Equipment		8,419.6	7,322.7
Accumulated Depreciation and Amortization		1,594.5	1,542
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,825.1	5,780.7
Other Noncurrent Assets
Regulatory Assets		378.7	347.2
Securitized Assets		891.2	1,118.7
Deferred Charges and Other Noncurrent Assets		114.8	73.3
TOTAL OTHER NONCURRENT ASSETS		1,384.7	1,539.2
TOTAL ASSETS		8,773.6	7,709.1
Current Liabilities
Advances from Affiliates		0	169.5
Accounts Payable		379.4	129.5
Affiliated Companies		30.2	30.5
Short-term Debt:
Long-term Debt Due Within One Year		266.1	263.1
Accrued Taxes		77.2	68.2
Accrued Interest		42.2	41.5
Obligations Under Capital Leases		4.2	3.6
Other Current Liabilities		76.4	94.8
TOTAL CURRENT LIABILITIES		871.5	797.1
Noncurrent Liabilities
Long-term Debt		3,383.2	2,954.6
Deferred Income Taxes		913.1	1,531.7
Regulatory Liabilities and Deferred Investment Tax Credits		1,320.5	660.8
Oklaunion Purchase Power Agreement		52	51.5
Obligations Under Capital Leases		18.5	14.8
Deferred Credits and Other Noncurrent Liabilities		63.4	56.3
TOTAL NONCURRENT LIABILITIES		5,732.2	5,254.9
TOTAL LIABILITIES		6,603.7	6,052
Rate Matters
Commitments and Contingencies
Equity
Paid-in Capital		1,057.9	857.9
Retained Earnings		1,124.6	814.1
Accumulated Other Comprehensive Income (Loss)		(12.6)	(14.9)
TOTAL EQUITY		2,169.9	1,657.1
TOTAL LIABILITIES AND EQUITY		8,773.6	7,709.1
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0	0
Advances to Affiliates		146.3	67.1
Accounts Receivable:
Customers		19.1	11.3
Affiliated Companies		93.2	66.6
Miscellaneous		1.3	0
Total Accounts Receivable		113.6	77.9
Materials and Supplies		13.6	5
Accrued Tax Benefits		46.6	26
Prepayments and Other Current Assets		7.6	2.8
TOTAL CURRENT ASSETS		327.7	178.8
Property, Plant and Equipment
Transmission		5,336.1	3,973.5
Other Property, Plant and Equipment		131.4	99.4
Construction Work in Progress		1,312.7	981.3
Total Property, Plant and Equipment		6,780.2	5,054.2
Accumulated Depreciation and Amortization		170.4	99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,609.8	4,954.6
Other Noncurrent Assets
Regulatory Assets		11.7	112.3
Deferred Tax Assets, Property, Plant and Equipment		117.8	102.2
Deferred Charges and Other Noncurrent Assets		1.1	1.9
TOTAL OTHER NONCURRENT ASSETS		130.6	216.4
TOTAL ASSETS		7,068.1	5,349.8
Current Liabilities
Advances from Affiliates		15.7	4.1
Accounts Payable		473.2	289.7
Affiliated Companies		52.9	43.1
Short-term Debt:
Long-term Debt Due Within One Year		50	0
Accrued Taxes		225.4	191.8
Accrued Interest		15	10.5
Obligations Under Capital Leases		0.1	0
Other Current Liabilities		4.1	10.9
TOTAL CURRENT LIABILITIES		836.3	550.1
Noncurrent Liabilities
Long-term Debt		2,500.4	1,932
Deferred Income Taxes		601.7	862.1
Regulatory Liabilities and Deferred Investment Tax Credits		493.7	44
Obligations Under Capital Leases		0.1	0
Deferred Credits and Other Noncurrent Liabilities		30.7	4
TOTAL NONCURRENT LIABILITIES		3,626.5	2,842.1
TOTAL LIABILITIES		4,462.8	3,392.2
Rate Matters
Commitments and Contingencies
Equity
Members' Capital		1,816.6	1,455
Retained Earnings		788.7	502.6
TOTAL MEMBER'S EQUITY		2,605.3	1,957.6
TOTAL LIABILITIES AND EQUITY		7,068.1	5,349.8
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.9	2.7
Restricted Cash		16.3	15.8
Advances to Affiliates		23.5	24.1
Accounts Receivable:
Customers		123.1	131.4
Affiliated Companies		69.3	54.4
Accrued Unbilled Revenues		74.1	52.7
Miscellaneous		1.1	0.9
Allowance for Uncollectible Accounts		(3.7)	(3.5)
Total Accounts Receivable		263.9	235.9
Fuel		89.3	112
Materials and Supplies		99.5	98.8
Risk Management Assets		24.9	2.6
Accrued Tax Benefits		0.1	4.2
Regulatory Asset for Under-Recovered Fuel Costs		88.8	68.4
Margin Deposits		14.4	17.5
Prepayments and Other Current Assets		12.6	9.7
TOTAL CURRENT ASSETS		636.2	591.7
Property, Plant and Equipment
Generation		6,446.9	6,332.8
Transmission		3,019.9	2,796.9
Distribution		3,763.8	3,569.1
Other Property, Plant and Equipment		427.9	373.5
Construction Work in Progress		483	390.3
Total Property, Plant and Equipment		14,141.5	13,462.6
Accumulated Depreciation and Amortization		3,896.4	3,636.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,245.1	9,825.8
Other Noncurrent Assets
Regulatory Assets		573.9	1,121.1
Securitized Assets		282.3	305.3
Long-term Risk Management Assets		1.1	0
Deferred Charges and Other Noncurrent Assets		190	133.3
TOTAL OTHER NONCURRENT ASSETS		1,047.3	1,559.7
TOTAL ASSETS		11,928.6	11,977.2
Current Liabilities
Advances from Affiliates		186	79.6
Accounts Payable		264.9	253.7
Affiliated Companies		92.7	82.6
Short-term Debt:
Long-term Debt Due Within One Year		249.2	503.1
Risk Management Liabilities		1.3	0.3
Customer Deposits		86.1	83.1
Accrued Taxes		94.5	107.6
Accrued Interest		40.5	40.6
Obligations Under Capital Leases		6.6	6.8
Other Current Liabilities		109	129.5
TOTAL CURRENT LIABILITIES		1,124.2	1,280.1
Noncurrent Liabilities
Long-term Debt		3,730.9	3,530.8
Long-term Risk Management Liabilities		0.2	0.9
Deferred Income Taxes		1,565.7	2,672.3
Regulatory Liabilities and Deferred Investment Tax Credits		1,454.9	627.8
Asset Retirement Obligations		100.2	108.8
Employee Benefits and Pension Obligations		73.3	108.5
Obligations Under Capital Leases		34.9	38.2
Deferred Credits and Other Noncurrent Liabilities		74.7	64.5
TOTAL NONCURRENT LIABILITIES		6,999.9	7,113.6
TOTAL LIABILITIES		8,124.1	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		1,714.1	1,502.8
Accumulated Other Comprehensive Income (Loss)		1.3	(8.4)
TOTAL EQUITY		3,804.5	3,583.5
TOTAL LIABILITIES AND EQUITY		11,928.6	11,977.2
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.3	1.2
Advances to Affiliates		12.4	12.5
Accounts Receivable:
Customers		56.4	60.2
Affiliated Companies		50	51
Accrued Unbilled Revenues		7.3	1.5
Miscellaneous		2	0.7
Allowance for Uncollectible Accounts		(0.1)	0
Total Accounts Receivable		115.6	113.4
Fuel		31.4	32.3
Materials and Supplies		160.6	150.8
Risk Management Assets		7.6	3.5
Accrued Tax Benefits		58.4	37.7
Regulatory Asset for Under-Recovered Fuel Costs		15	26.1
Accrued Reimbursement of Spent Nuclear Fuel Costs		10.8	22.1
Prepayments and Other Current Assets		20.9	19.9
TOTAL CURRENT ASSETS		434	419.5
Property, Plant and Equipment
Generation		4,445.9	4,056.1
Transmission		1,504	1,472.8
Distribution		2,069.3	1,899.3
Other Property, Plant and Equipment		595.2	550.2
Construction Work in Progress		460.2	654.2
Total Property, Plant and Equipment		9,074.6	8,632.6
Accumulated Depreciation and Amortization		3,024.2	3,005.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,050.4	5,627.5
Other Noncurrent Assets
Regulatory Assets		579.4	916.6
Spent Nuclear Fuel and Decommissioning Trusts		2,527.6	2,256.2
Long-term Risk Management Assets		0.7	0
Deferred Charges and Other Noncurrent Assets		179.9	121.5
TOTAL OTHER NONCURRENT ASSETS		3,287.6	3,294.3
TOTAL ASSETS		9,772	9,341.3
Current Liabilities
Advances from Affiliates		211.6	215.2
Accounts Payable		154.5	179
Affiliated Companies		98.3	75.6
Short-term Debt:
Long-term Debt Due Within One Year		474.7	209.3
Risk Management Liabilities		3.5	0.3
Customer Deposits		37.7	34.3
Accrued Taxes		81.3	77.2
Accrued Interest		37.5	31.7
Obligations Under Capital Leases		5.8	9.4
Regulatory Liability for Over-Recovered Fuel Costs		2.7	0
Other Current Liabilities		106.4	123.4
TOTAL CURRENT LIABILITIES		1,211.3	955.4
Noncurrent Liabilities
Long-term Debt		2,270.4	2,262.1
Long-term Risk Management Liabilities		0.1	0.8
Deferred Income Taxes		953.8	1,527.4
Regulatory Liabilities and Deferred Investment Tax Credits		1,708.7	1,065.5
Asset Retirement Obligations		1,321.6	1,257.9
Obligations Under Capital Leases		34.3	35.3
Deferred Credits and Other Noncurrent Liabilities		88.5	120.4
TOTAL NONCURRENT LIABILITIES		6,343.1	6,234.1
TOTAL LIABILITIES		7,554.4	7,189.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,192.2	1,130.5
Accumulated Other Comprehensive Income (Loss)		(12.1)	(16.2)
TOTAL EQUITY		2,217.6	2,151.8
TOTAL LIABILITIES AND EQUITY		9,772	9,341.3
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.1	3.1
Restricted Cash		26.6	27.2
Advances to Affiliates		0	24.2
Accounts Receivable:
Customers		67.8	51.1
Affiliated Companies		70.2	66.3
Accrued Unbilled Revenues		29.7	21
Miscellaneous		1.9	0.9
Allowance for Uncollectible Accounts		(0.6)	(0.4)
Total Accounts Receivable		169	138.9
Materials and Supplies		41.9	45.9
Renewable Energy Credits		25	20.4
Risk Management Assets		0.6	0.2
Regulatory Asset for Under-Recovered Fuel Costs		115.9	0
Prepayments and Other Current Assets		15.8	11
TOTAL CURRENT ASSETS		397.9	270.9
Property, Plant and Equipment
Transmission		2,419.2	2,319.2
Distribution		4,626.4	4,457.2
Other Property, Plant and Equipment		495.9	443.7
Construction Work in Progress		410.1	221.5
Total Property, Plant and Equipment		7,951.6	7,441.6
Accumulated Depreciation and Amortization		2,184.8	2,116
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,766.8	5,325.6
Other Noncurrent Assets
Notes Receivable - Affiliated		32.3	32.3
Regulatory Assets		652.8	1,107.5
Securitized Assets		37.7	62.1
Deferred Charges and Other Noncurrent Assets		374.2	295.5
TOTAL OTHER NONCURRENT ASSETS		1,097	1,497.4
TOTAL ASSETS		7,261.7	7,093.9
Current Liabilities
Advances from Affiliates		87.8	0
Accounts Payable		205.8	175.4
Affiliated Companies		118.2	95.6
Short-term Debt:
Long-term Debt Due Within One Year		397	46.4
Risk Management Liabilities		6.4	5.9
Customer Deposits		69.2	71
Accrued Taxes		512.5	520.3
Accrued Interest		31	31.2
Obligations Under Capital Leases		4.3	4.2
Regulatory Liability for Over-Recovered Fuel Costs		0	4.2
Other Current Liabilities		165.9	236
TOTAL CURRENT LIABILITIES		1,593.8	1,181.8
Noncurrent Liabilities
Long-term Debt		1,322.3	1,717.5
Long-term Risk Management Liabilities		126	113.1
Deferred Income Taxes		762.9	1,346.1
Regulatory Liabilities and Deferred Investment Tax Credits		1,100.2	506.2
Obligations Under Capital Leases		7.9	8.1
Deferred Credits and Other Noncurrent Liabilities		46.2	111.7
TOTAL NONCURRENT LIABILITIES		3,357.6	3,794.6
TOTAL LIABILITIES		4,951.4	4,976.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		1,148.4	954.5
Accumulated Other Comprehensive Income (Loss)		1.9	3
TOTAL EQUITY		2,310.3	2,117.5
TOTAL LIABILITIES AND EQUITY		7,261.7	7,093.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1.6	1.5
Accounts Receivable:
Customers		32.5	27.5
Affiliated Companies		32.9	26.8
Miscellaneous		4.1	4.4
Allowance for Uncollectible Accounts		(0.1)	(0.2)
Total Accounts Receivable		69.4	58.5
Fuel		12.5	22.9
Materials and Supplies		42	44.6
Risk Management Assets		6.4	0.8
Accrued Tax Benefits		28.1	27.3
Regulatory Asset for Under-Recovered Fuel Costs		36.7	33.8
Prepayments and Other Current Assets		8.6	6
TOTAL CURRENT ASSETS		205.3	195.4
Property, Plant and Equipment
Generation		1,577.2	1,559.3
Transmission		858.8	832.8
Distribution		2,445.1	2,322.4
Other Property, Plant and Equipment		287.4	233.2
Construction Work in Progress		111.3	148.2
Total Property, Plant and Equipment		5,279.8	5,095.9
Accumulated Depreciation and Amortization		1,393.6	1,272.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,886.2	3,823.2
Other Noncurrent Assets
Regulatory Assets		368.1	340.2
Employee Benefits and Pension Assets		40	10.4
Deferred Charges and Other Noncurrent Assets		8.7	10
TOTAL OTHER NONCURRENT ASSETS		416.8	360.6
TOTAL ASSETS		4,508.3	4,379.2
Current Liabilities
Advances from Affiliates		149.6	52
Accounts Payable		102.4	116.3
Affiliated Companies		48	56.2
Short-term Debt:
Long-term Debt Due Within One Year		0.5	0.5
Customer Deposits		54.1	49.7
Accrued Taxes		22.6	21
Accrued Interest		14.1	13.9
Obligations Under Capital Leases		3.5	4.1
Provision for Refund		0	46.1
Other Current Liabilities		44.7	47.8
TOTAL CURRENT LIABILITIES		436	403.5
Noncurrent Liabilities
Long-term Debt		1,286	1,285.5
Deferred Income Taxes		642	1,058.8
Regulatory Liabilities and Deferred Investment Tax Credits		853.5	339.7
Asset Retirement Obligations		53	52.8
Obligations Under Capital Leases		8.3	9.8
Deferred Credits and Other Noncurrent Liabilities		22.5	24.8
TOTAL NONCURRENT LIABILITIES		2,857	2,761.6
TOTAL LIABILITIES		3,293	3,165.1
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		691.5	689.5
Accumulated Other Comprehensive Income (Loss)		2.6	3.4
TOTAL EQUITY		1,215.3	1,214.1
TOTAL LIABILITIES AND EQUITY		4,508.3	4,379.2
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.6	10.3
Advances to Affiliates		2	169.8
Accounts Receivable:
Customers		70.9	48.5
Affiliated Companies		30.2	29.3
Miscellaneous		25.8	17.5
Allowance for Uncollectible Accounts		(1.3)	(1.2)
Total Accounts Receivable		125.6	94.1
Fuel		123.6	107.1
Materials and Supplies		67.9	68.4
Risk Management Assets		6.4	0.9
Accrued Tax Benefits		3.9	51.5
Regulatory Asset for Under-Recovered Fuel Costs		14.1	8.4
Prepayments and Other Current Assets		35.3	35.5
TOTAL CURRENT ASSETS		380.4	546
Property, Plant and Equipment
Generation		4,624.9	4,607.6
Transmission		1,679.8	1,584.2
Distribution		2,095.8	2,020.6
Other Property, Plant and Equipment		684.1	670.4
Construction Work in Progress		233.2	113.8
Total Property, Plant and Equipment		9,317.8	8,996.6
Accumulated Depreciation and Amortization		2,685.8	2,567.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,632	6,429.5
Other Noncurrent Assets
Regulatory Assets		220.6	551.2
Deferred Charges and Other Noncurrent Assets		109.9	99.9
TOTAL OTHER NONCURRENT ASSETS		330.5	651.1
TOTAL ASSETS		7,342.9	7,626.6
Current Liabilities
Advances from Affiliates		118.7	0
Accounts Payable		160.4	117.5
Affiliated Companies		63.7	68.5
Short-term Debt:
Other Short-term Debt		22	0
Long-term Debt Due Within One Year		3.7	353.7
Risk Management Liabilities		0.2	0.3
Customer Deposits		62.1	62.1
Accrued Taxes		39	40.9
Accrued Interest		38.9	45.1
Obligations Under Capital Leases		11.2	11.8
Regulatory Liability for Over-Recovered Fuel Costs		8.7	3.8
Other Current Liabilities		78.7	83.9
TOTAL CURRENT LIABILITIES		598.6	783.8
Noncurrent Liabilities
Long-term Debt		2,438.2	2,325.4
Deferred Income Taxes		917.7	1,606.9
Regulatory Liabilities and Deferred Investment Tax Credits		896.4	438.9
Asset Retirement Obligations		160.3	147.1
Employee Benefits and Pension Obligations		19.5	34.1
Obligations Under Capital Leases		57.8	65.5
Deferred Credits and Other Noncurrent Liabilities		19.9	9.7
TOTAL NONCURRENT LIABILITIES		4,509.8	4,627.6
TOTAL LIABILITIES		5,108.4	5,411.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,426.6	1,411.9
Accumulated Other Comprehensive Income (Loss)		(4)	(9.4)
TOTAL COMMON SHAREHOLDERS' EQUITY		2,234.9	2,214.8
Noncontrolling Interests		(0.4)	0.4
TOTAL EQUITY		2,234.5	2,215.2
TOTAL LIABILITIES AND EQUITY		$ 7,342.9	$ 7,626.6
[1]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[2]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Securitized Assets	$ 1,211.2	$ 1,486.1
Current Assets
Cash and Cash Equivalents	214.6	210.5
Restricted Cash	198	193
Other Temporary Investments	161.7	138.7
Fuel	387.7	423.8
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	3,706.3	3,444.3
Accumulated Depreciation and Amortization	17,167	16,397.3
Current Liabilities
Long-term Debt Due Within One Year	1,753.7	2,878
Accrued Interest	234.5	227.2
Noncurrent Liabilities
Long-term Debt	$ 19,419.6	$ 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	512,210,644	512,048,520
Treasury Stock, Shares	20,205,046	20,336,592
AEP Texas Central Transition Funding Co [Member]
Securitized Assets	$ 870	$ 1,100
Subsidiaries [Member]
Current Assets
Restricted Cash	198	189.2
Other Temporary Investments	155.4	133.3
Current Liabilities
Long-term Debt Due Within One Year	406.9	427.5
Noncurrent Liabilities
Long-term Debt	1,401.5	1,737.5
AEP Texas Inc. [Member]
Securitized Assets	891.2	1,118.7
Current Assets
Cash and Cash Equivalents	2	0.6
Restricted Cash	155.2	146.3
Fuel	3.6	9.8
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	461	436.4
Accumulated Depreciation and Amortization	1,594.5	1,542
Current Liabilities
Long-term Debt Due Within One Year	266.1	263.1
Accrued Interest	42.2	41.5
Noncurrent Liabilities
Long-term Debt	3,383.2	2,954.6
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member]
Securitized Assets	869.5	1,088.3
Current Liabilities
Long-term Debt Due Within One Year	236.1	222.2
Accrued Interest	15.9	20.2
Noncurrent Liabilities
Long-term Debt	790.1	1,023.6
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents	0	0
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	131.4	99.4
Accumulated Depreciation and Amortization	170.4	99.6
Current Liabilities
Long-term Debt Due Within One Year	50	0
Accrued Interest	15	10.5
Noncurrent Liabilities
Long-term Debt	2,500.4	1,932
Appalachian Power Co [Member]
Securitized Assets	282.3	305.3
Current Assets
Cash and Cash Equivalents	2.9	2.7
Restricted Cash	16.3	15.8
Fuel	89.3	112
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	427.9	373.5
Accumulated Depreciation and Amortization	3,896.4	3,636.8
Current Liabilities
Long-term Debt Due Within One Year	249.2	503.1
Accrued Interest	40.5	40.6
Noncurrent Liabilities
Long-term Debt	$ 3,730.9	$ 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	$ 1.3	$ 1.2
Fuel	31.4	32.3
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	595.2	550.2
Accumulated Depreciation and Amortization	3,024.2	3,005.1
Current Liabilities
Long-term Debt Due Within One Year	474.7	209.3
Accrued Interest	37.5	31.7
Noncurrent Liabilities
Long-term Debt	$ 2,270.4	$ 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	$ 96.3	$ 130.9
Ohio Power Co [Member]
Securitized Assets	37.7	62.1
Current Assets
Cash and Cash Equivalents	3.1	3.1
Restricted Cash	26.6	27.2
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	495.9	443.7
Accumulated Depreciation and Amortization	2,184.8	2,116
Current Liabilities
Long-term Debt Due Within One Year	397	46.4
Accrued Interest	31	31.2
Noncurrent Liabilities
Long-term Debt	$ 1,322.3	$ 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]
Securitized Assets	$ 38	$ 62
Current Liabilities
Long-term Debt Due Within One Year	47	46.3
Noncurrent Liabilities
Long-term Debt	47.5	93.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	1.6	1.5
Fuel	12.5	22.9
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	287.4	233.2
Accumulated Depreciation and Amortization	1,393.6	1,272.7
Current Liabilities
Long-term Debt Due Within One Year	0.5	0.5
Accrued Interest	14.1	13.9
Noncurrent Liabilities
Long-term Debt	$ 1,286	$ 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	$ 1.6	$ 10.3
Fuel	123.6	107.1
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	684.1	670.4
Accumulated Depreciation and Amortization	2,685.8	2,567.1
Current Liabilities
Long-term Debt Due Within One Year	3.7	353.7
Accrued Interest	38.9	45.1
Noncurrent Liabilities
Long-term Debt	$ 2,438.2	$ 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	41.5	34.3
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	266.7	267.5
Accumulated Depreciation and Amortization	$ 165.9	$ 155.6

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Activites
NET INCOME (LOSS)	$ 1,928.9	$ 618	$ 2,052.3
Income (Loss) from Discontinued Operations, Net of Tax	0	(2.5)	283.7
Income (Loss) from Continuing Operations	1,928.9	620.5	1,768.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	1,997.2	1,962.3	2,009.7
Deferred Income Taxes	901.5	(50)	808.2
Asset Impairments and Other Related Charges	87.1	2,267.8	0
Carrying Costs Income	18.6	16.2	23.5
Allowance for Equity Funds Used During Construction	(93.7)	(113.2)	(131.9)
Mark-to-Market of Risk Management Contracts	(23.3)	150.8	52.5
Amortization of Nuclear Fuel	129.1	128.6	145
Pension and Postemployment Benefit Reserves	27.8	21.6	33.2
Pension Contributions to Qualified Plan Trust	(93.3)	(84.8)	(91.8)
Property Taxes	(29.5)	(19)	(52.4)
Deferred Fuel Over/Under-Recovery, Net	84.4	(65.5)	137.8
Gain on Sale of Merchant Generation Assets	(226.4)	0	0
Deferral of Ohio Capacity Costs, Net	83.2	88.1	65.5
Provision for Refund - Global Settlement	(98.2)	120.3	0
Disposition of Tanners Creek Plant Site	0	(93.5)	0
Change in Other Noncurrent Assets	(423.9)	(454.6)	(129.2)
Change in Other Noncurrent Liabilities	181.7	15.4	(89)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	28.5	(226.6)	200.2
Fuel, Materials and Supplies	17.9	60.2	(38.6)
Accounts Payable	(58)	164.9	16.5
Accrued Taxes, Net	91.9	42.8	120.2
Other Current Assets	(60.7)	14.2	(26.7)
Other Current Liabilities	(181.8)	(28.5)	(49.1)
Net Cash Flows from (Used for) Continuing Operating Activities	4,270.4	4,521.8	4,748.7
Investing Activities
Construction Expenditures	(5,691.3)	(4,781.1)	(4,508)
Purchases of Investment Securities	(2,314.7)	(3,002.3)	(2,282.7)
Sales of Investment Securities	2,256.3	2,957.7	2,218.4
Acquisitions of Nuclear Fuel	(108)	(128.5)	(92)
Acquisitions of Assets	(6.8)	(107.9)	(5.3)
Proceeds from Sale of Merchant Generation Assets	2,159.6	0	0
Other Investing Activities	48.5	15.5	97
Net Cash Flows from (Used for) Continuing Investing Activities	(3,656.4)	(5,046.6)	(4,572.6)
Financing Activities
Issuance of Common Stock, Net	12.2	34.2	81.6
Issuance of Long-term Debt	3,854.1	2,594.9	3,436.6
Change in Short-term Debt, Net	(74.4)	913	(546)
Retirement of Long-term Debt	(3,087.9)	(1,794.9)	(2,397.9)
Make Whole Premium on Extinguishment of Long-term Debt	(46.1)	0	(92.7)
Principal Payments for Capital Lease Obligations	(67.3)	(106.6)	(99)
Dividends Paid on Common Stock	(1,191.9)	(1,121)	(1,059)
Other Financing Activities	(3.6)	(15.7)	14.7
Net Cash Flows from (Used for) Continuing Financing Activities	(604.9)	503.9	(661.7)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Cash Flows from (Used for) Discontinued Operating Activities	0	(2.5)	69.8
Net Cash Flows from (Used for) Discontinued Investing Activities	0	0	548.8
Net Cash Flows from (Used for) Discontinued Financing Activities	0	0	(127.7)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	9.1	(23.4)	5.3
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	403.5	426.9	421.6
Cash and Cash Equivalents at Beginning of Period	210.5
Cash, Cash Equivalents and Restricted Cash at End of Period	412.6	403.5	426.9
Cash and Cash Equivalents at End of Period	214.6	210.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	858.3	848.5	857.2
Net Cash Paid (Received) for Income Taxes	(1.1)	29.5	120.2
Noncash Acquisitions Under Capital Leases	60.7	86.1	150.2
Construction Expenditures Included in Current Liabilities as of December 31,	1,330.8	858	741.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	0	2.1	37.9
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	2.6	0.7	2.2
AEP Texas Inc. [Member]
Operating Activites
NET INCOME (LOSS)	310.5	146.6	120.3
Income (Loss) from Discontinued Operations, Net of Tax	0	(48.8)	(1.4)
Income (Loss) from Continuing Operations	310.5	195.4	121.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	450.1	413.9	468.9
Deferred Income Taxes	63.3	29.5	(7.1)
Asset Impairments and Other Related Charges		72.7	0
Allowance for Equity Funds Used During Construction	(6.8)	(9.2)	(6.7)
Mark-to-Market of Risk Management Contracts	(0.3)	(0.5)	(0.7)
Pension Contributions to Qualified Plan Trust	(8.8)	(8.2)	(8.5)
Change in Regulatory Asset - Catastrophe Reserve	(99.2)	(0.9)	(3.9)
Change in Other Noncurrent Assets	(49.4)	(44.1)	(68.5)
Change in Other Noncurrent Liabilities	8.8	(10.3)	(43.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(23.5)	(22.6)	9.9
Fuel, Materials and Supplies	3.2	5.9	(4.4)
Accounts Payable	30.8	(3)	(12.3)
Accrued Taxes, Net	(31.3)	(22.6)	46.9
Other Current Assets	0.6	(0.2)	(0.1)
Other Current Liabilities	(15.3)	(6.5)	3.1
Net Cash Flows from (Used for) Continuing Operating Activities	632.7	516.6	495.2
Investing Activities
Construction Expenditures	(990.9)	(640.9)	(593.4)
Change in Advances to Affiliates, Net	(103.3)	139	(138)
Other Investing Activities	18.9	10.4	29.1
Net Cash Flows from (Used for) Continuing Investing Activities	(1,075.3)	(491.5)	(702.3)
Financing Activities
Capital Contributions from Member	200	53	272.3
Issuance of Long-term Debt	749.6	199.2	370.1
Change in Advances from Affiliates, Net	(169.5)	117	(142)
Retirement of Long-term Debt	(323.1)	(428.7)	(273.7)
Principal Payments for Capital Lease Obligations	(3.9)	(3.4)	(2.9)
Dividends Paid on Common Stock	0	(34)	(29)
Other Financing Activities	(0.2)	0.8	0.3
Net Cash Flows from (Used for) Continuing Financing Activities	452.9	(96.1)	195.1
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Cash Flows from (Used for) Discontinued Operating Activities	0	42.4	0.6
Net Cash Flows from (Used for) Discontinued Investing Activities	0	11.7	18.8
Net Cash Flows from (Used for) Discontinued Financing Activities	0	(44.6)	(15.9)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	10.3	(61.5)	(8.5)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	146.9	208.4	216.9
Cash and Cash Equivalents at Beginning of Period	0.6
Cash, Cash Equivalents and Restricted Cash at End of Period	157.2	146.9	208.4
Cash and Cash Equivalents at End of Period	2	0.6
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	134.6	145.6	144
Net Cash Paid (Received) for Income Taxes	(28.3)	38.2	8.1
Noncash Acquisitions Under Capital Leases	8.2	7.1	6.1
Construction Expenditures Included in Current Liabilities as of December 31,	325.7	100.1	72.8
Distribution of CSW Energy, Inc to Parent	0	185.5	0
AEP Transmission Co [Member]
Operating Activites
NET INCOME (LOSS)	286.1	192.7	132.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	97.1	65.9	42.4
Deferred Income Taxes	272.8	223.1	183.2
Allowance for Equity Funds Used During Construction	(52.3)	(52.3)	(53)
Property Taxes	(15.6)	(15.3)	(25.6)
Change in Other Noncurrent Assets	9.8	(2.8)	1.8
Change in Other Noncurrent Liabilities	27.3	4.4	0.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(34.5)	(22.6)	(26.3)
Fuel, Materials and Supplies	(8.6)	(5)	0
Accounts Payable	9.8	14.3	(3.5)
Accrued Taxes, Net	13	143.8	(53.6)
Increase (Decrease) in Interest Payable, Net	4.5	2.6	0.9
Other Current Assets	(4.8)	0.1	(0.4)
Other Current Liabilities	0.2	0	0
Net Cash Flows from (Used for) Operating Activities	604.8	548.9	199.4
Investing Activities
Construction Expenditures	(1,513.4)	(1,159.5)	(1,007.8)
Change in Advances to Affiliates, Net	(79.2)	29	65.4
Acquisitions of Assets	(9.1)	(6.5)	(1.1)
Other Investing Activities	6.1	2	3.4
Net Cash Flows from (Used for) Investing Activities	(1,595.6)	(1,135)	(940.1)
Financing Activities
Capital Contributions from Member	361.6	212	279
Issuance of Long-term Debt	617.6	686.9	449
Change in Advances from Affiliates, Net	11.6	(12.8)	12.7
Retirement of Long-term Debt	0	(300)	0
Net Cash Flows from (Used for) Financing Activities	990.8	586.1	740.7
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	0	0	0
Cash and Cash Equivalents at Beginning of Period	0	0	0
Cash and Cash Equivalents at End of Period	0	0	0
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	61.2	42	32.5
Net Cash Paid (Received) for Income Taxes	(107.3)	(235.1)	(11.2)
Noncash Acquisitions Under Capital Leases	0.2	0	0
Construction Expenditures Included in Current Liabilities as of December 31,	473.7	298.3	208
Appalachian Power Co [Member]
Operating Activites
NET INCOME (LOSS)	331.3	369.1	340.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	407.9	388.5	388.8
Deferred Income Taxes	171.5	130.7	227.5
Carrying Costs Income	1.4	0.4	1.2
Allowance for Equity Funds Used During Construction	(9.2)	(11.7)	(13.8)
Mark-to-Market of Risk Management Contracts	(23.1)	9.4	4.8
Pension Contributions to Qualified Plan Trust	(10.2)	(8.8)	(10)
Deferred Fuel Over/Under-Recovery, Net	(20.5)	22.2	(19.4)
Change in Other Noncurrent Assets	12.8	3.4	(56.9)
Change in Other Noncurrent Liabilities	11.9	(26.1)	(34.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(28)	(48)	51.7
Fuel, Materials and Supplies	22.3	12.9	(10.9)
Accounts Payable	37.5	19.5	0.3
Accrued Taxes, Net	(12.7)	53.7	(60.2)
Other Current Assets	0.7	(9.8)	(4.2)
Other Current Liabilities	(10.8)	(9.9)	(10.3)
Net Cash Flows from (Used for) Operating Activities	880	894.7	792.4
Investing Activities
Construction Expenditures	(818.1)	(646.7)	(636.2)
Change in Advances to Affiliates, Net	0.6	1.5	22.9
Other Investing Activities	15.2	13.3	13.1
Net Cash Flows from (Used for) Investing Activities	(802.3)	(631.9)	(600.2)
Financing Activities
Issuance of Long-term Debt	320.9	314	726.3
Change in Advances from Affiliates, Net	106.4	(101.4)	181
Retirement of Long-term Debt	(377.9)	(213.6)	(672.6)
Retirement of Long-term Debt - Affiliated	0	0	(86)
Make Whole Premium on Extinguishment of Long-term Debt	0	0	(92.7)
Principal Payments for Capital Lease Obligations	(6.9)	(6.4)	(5.5)
Dividends Paid on Common Stock	(120)	(255)	(243.8)
Other Financing Activities	0.5	0.5	0.5
Net Cash Flows from (Used for) Financing Activities	(77)	(261.9)	(192.8)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	0.7	0.9	(0.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	18.5	17.6	18.2
Cash and Cash Equivalents at Beginning of Period	2.7
Cash, Cash Equivalents and Restricted Cash at End of Period	19.2	18.5	17.6
Cash and Cash Equivalents at End of Period	2.9	2.7
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	183.6	181.8	196.7
Net Cash Paid (Received) for Income Taxes	31.2	22.1	30.4
Noncash Acquisitions Under Capital Leases	3.5	6.1	31.8
Construction Expenditures Included in Current Liabilities as of December 31,	126.3	151.6	90.4
Noncash Contribution of Amos Plant from Parent	0	0	19.1
Indiana Michigan Power Co [Member]
Operating Activites
NET INCOME (LOSS)	186.7	239.9	204.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	210.9	191.7	198.4
Deferred Income Taxes	200.7	105.1	94.2
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	8.5	(48.4)	11.2
Asset Impairments and Other Related Charges	0	10.5	0
Carrying Costs Income	12.7	10.1	8.3
Allowance for Equity Funds Used During Construction	(11.1)	(15.3)	(11.6)
Mark-to-Market of Risk Management Contracts	(2.3)	2	14.6
Amortization of Nuclear Fuel	129.1	128.6	145
Pension Contributions to Qualified Plan Trust	(13)	(12.7)	(14.6)
Deferred Fuel Over/Under-Recovery, Net	13.7	(14.8)	(17.7)
Disposition of Tanners Creek Plant Site	0	(93.5)	0
Change in Other Noncurrent Assets	(101.1)	(66.5)	(19.9)
Change in Other Noncurrent Liabilities	37.4	58.2	13.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(1.1)	0.5	16
Fuel, Materials and Supplies	(7.5)	20.9	11.7
Accounts Payable	17.6	11.6	3.7
Accrued Taxes, Net	(16.6)	6	(14.3)
Other Current Assets	14.5	8	(4.8)
Other Current Liabilities	(5.1)	(2.1)	(7)
Net Cash Flows from (Used for) Operating Activities	661.3	529.7	623.5
Investing Activities
Construction Expenditures	(648.5)	(596.9)	(459.8)
Change in Advances to Affiliates, Net	0.1	(0.8)	1.8
Purchases of Investment Securities	(2,300.5)	(3,000)	(2,272)
Sales of Investment Securities	2,256.3	2,957.7	2,218.4
Acquisitions of Nuclear Fuel	(108)	(128.5)	(92)
Other Investing Activities	9.7	8.4	9.4
Net Cash Flows from (Used for) Investing Activities	(790.9)	(760.1)	(594.2)
Financing Activities
Issuance of Long-term Debt	530.1	569.4	310.7
Change in Advances from Affiliates, Net	(3.6)	(79.1)	151.8
Retirement of Long-term Debt	(260.7)	(100.2)	(332.1)
Principal Payments for Capital Lease Obligations	(12)	(35.3)	(40.2)
Dividends Paid on Common Stock	(125)	(125)	(120)
Other Financing Activities	0.9	0.7	0.6
Net Cash Flows from (Used for) Financing Activities	129.7	230.5	(29.2)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	0.1	0.1
Cash and Cash Equivalents at Beginning of Period	1.2	1.1	1
Cash and Cash Equivalents at End of Period	1.3	1.2	1.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	94.8	83.3	84.5
Net Cash Paid (Received) for Income Taxes	(89.9)	(39.5)	21.2
Noncash Acquisitions Under Capital Leases	7.1	18.2	3
Construction Expenditures Included in Current Liabilities as of December 31,	88.5	106.2	95.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	0	2.1	37.9
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	2.6	0.7	2.2
Ohio Power Co [Member]
Operating Activites
NET INCOME (LOSS)	323.9	282.2	232.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	225.9	238.6	217.5
Generation Deferrals	0	(82.7)	(30.7)
Amortization of Generation Deferrals	229.2	242.9	169.1
Deferred Income Taxes	147.9	(39.2)	37.6
Carrying Costs Income	3.6	19.9	11.8
Allowance for Equity Funds Used During Construction	(6.4)	(6)	(8.8)
Mark-to-Market of Risk Management Contracts	13	134.6	31.7
Pension Contributions to Qualified Plan Trust	(8.2)	(7.1)	(7.7)
Property Taxes	(17.9)	(9.8)	(24.7)
Provision for Refund - Global Settlement	(98.2)	120.3	0
Change in Regulatory Assets	(70.7)	(139.8)	86.2
Change in Other Noncurrent Assets	(51.1)	(44.6)	(52.9)
Change in Other Noncurrent Liabilities	15.8	31	27.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(30.1)	(26.6)	61.9
Fuel, Materials and Supplies	(11.1)	(2.1)	(25.2)
Accounts Payable	11.6	13.7	(64.3)
Accrued Taxes, Net	(9.4)	(6)	111.8
Other Current Assets	(9.2)	0	(2.8)
Other Current Liabilities	(29.2)	(33.2)	(16.3)
Net Cash Flows from (Used for) Operating Activities	622.2	646.3	731.2
Investing Activities
Construction Expenditures	(567.7)	(416.2)	(453.3)
Change in Advances to Affiliates, Net	24.2	306.9	(18.6)
Proceeds from Notes Receivable - Affiliated	0	0	86
Other Investing Activities	12.6	12	13.1
Net Cash Flows from (Used for) Investing Activities	(530.9)	(97.3)	(372.8)
Financing Activities
Change in Advances from Affiliates, Net	87.8	0	0
Retirement of Long-term Debt	(46.4)	(395.9)	(131.5)
Principal Payments for Capital Lease Obligations	(4.1)	(4.2)	(3.9)
Dividends Paid on Common Stock	(130)	(150)	(225)
Other Financing Activities	0.8	0.6	1.2
Net Cash Flows from (Used for) Financing Activities	(91.9)	(549.5)	(359.2)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(0.6)	(0.5)	(0.8)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	30.3	30.8	31.6
Cash and Cash Equivalents at Beginning of Period	3.1
Cash, Cash Equivalents and Restricted Cash at End of Period	29.7	30.3	30.8
Cash and Cash Equivalents at End of Period	3.1	3.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	100	109.9	121.6
Net Cash Paid (Received) for Income Taxes	48.5	220.4	26.1
Noncash Acquisitions Under Capital Leases	4.5	3.4	2.7
Construction Expenditures Included in Current Liabilities as of December 31,	87.8	44.6	34.3
Public Service Co Of Oklahoma [Member]
Operating Activites
NET INCOME (LOSS)	72	100	92.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	130.4	130.2	117.5
Deferred Income Taxes	124.7	82.5	58.3
Allowance for Equity Funds Used During Construction	(0.5)	(6.2)	(8.8)
Mark-to-Market of Risk Management Contracts	(5.6)	(0.4)	(1.4)
Pension Contributions to Qualified Plan Trust	(5.3)	(5.6)	(5.8)
Deferred Fuel Over/Under-Recovery, Net	(5.4)	(109.9)	111.8
Provision for Refund	(43.5)	46.1	0
Change in Regulatory Assets	(14.9)	(16.6)	(14.3)
Change in Other Noncurrent Assets	(12.3)	(19.3)	(25.7)
Change in Other Noncurrent Liabilities	4.5	(0.1)	5
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(10.9)	(9)	6.9
Fuel, Materials and Supplies	13	2	(2.2)
Accounts Payable	(10.7)	25.7	6.4
Accrued Taxes, Net	0.8	7.4	(10.2)
Other Current Assets	(2.1)	0.8	(1)
Other Current Liabilities	3.9	(10.4)	10.2
Net Cash Flows from (Used for) Operating Activities	238.1	217.2	339.2
Investing Activities
Construction Expenditures	(266.1)	(351.1)	(359.1)
Change in Advances to Affiliates, Net	0	80.6	(80.6)
Other Investing Activities	4.6	11	9.2
Net Cash Flows from (Used for) Investing Activities	(261.5)	(259.5)	(430.5)
Financing Activities
Issuance of Long-term Debt	0	274.2	248.8
Change in Advances from Affiliates, Net	97.6	52	(154.2)
Retirement of Long-term Debt	(0.5)	(275.4)	(0.4)
Principal Payments for Capital Lease Obligations	(3.9)	(3.8)	(3.6)
Dividends Paid on Common Stock	(70)	(5)	0
Other Financing Activities	0.3	0.4	0.7
Net Cash Flows from (Used for) Financing Activities	23.5	42.4	91.3
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	0.1	0
Cash and Cash Equivalents at Beginning of Period	1.5	1.4	1.4
Cash and Cash Equivalents at End of Period	1.6	1.5	1.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	61.5	60.1	54.8
Net Cash Paid (Received) for Income Taxes	(72.6)	(37.7)	7.9
Noncash Acquisitions Under Capital Leases	2.1	3.1	3.6
Construction Expenditures Included in Current Liabilities as of December 31,	23.1	33.6	47.4
Southwestern Electric Power Co [Member]
Operating Activites
NET INCOME (LOSS)	137.5	169.7	196
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	217.4	196.5	192
Deferred Income Taxes	80.5	162.6	41.9
Asset Impairments and Other Related Charges	33.6	0	0
Allowance for Equity Funds Used During Construction	(2.4)	(11)	(26.4)
Mark-to-Market of Risk Management Contracts	(5.6)	(5.1)	3.4
Pension Contributions to Qualified Plan Trust	(8.9)	(8.3)	(8.1)
Deferred Fuel Over/Under-Recovery, Net	(0.8)	(8.9)	28.3
Change in Regulatory Liabilities	(12.3)	(22)	(21.4)
Change in Other Noncurrent Assets	(9.2)	(13)	(1.6)
Change in Other Noncurrent Liabilities	17	6	15.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(32.9)	(5.7)	20.5
Fuel, Materials and Supplies	(16)	38.1	(22.9)
Accounts Payable	10.5	3.5	(10.7)
Accrued Taxes, Net	45.7	(68.9)	29.7
Other Current Assets	5.2	(13.9)	1.1
Other Current Liabilities	(14.6)	(15.3)	(9.6)
Net Cash Flows from (Used for) Operating Activities	444.7	404.3	427.6
Investing Activities
Construction Expenditures	(404.1)	(426.3)	(540.6)
Change in Advances to Affiliates, Net	167.8	(167.8)	41
Proceeds from Sales of Assets	12.6	1.1	1.6
Other Investing Activities	3.1	(1)	4.3
Net Cash Flows from (Used for) Investing Activities	(220.6)	(594)	(493.7)
Financing Activities
Issuance of Long-term Debt	114.6	406.7	445.9
Change in Advances from Affiliates, Net	118.7	(58.3)	58.3
Change in Short-term Debt, Net	22	0	0
Retirement of Long-term Debt	(353.7)	(3.3)	(306.8)
Principal Payments for Capital Lease Obligations	(11.3)	(27.1)	(17.7)
Dividends Paid on Common Stock	(110)	(120)	(120)
Dividends Paid on Common Stock	(13.6)	(4.2)	(3.6)
Other Financing Activities	0.5	1	0.8
Net Cash Flows from (Used for) Financing Activities	(232.8)	194.8	56.9
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	(8.7)	5.1	(9.2)
Cash and Cash Equivalents at Beginning of Period	10.3	5.2	14.4
Cash and Cash Equivalents at End of Period	1.6	10.3	5.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	124.4	118	112.6
Net Cash Paid (Received) for Income Taxes	(75.3)	(32)	15.4
Noncash Acquisitions Under Capital Leases	3.3	5.9	7.4
Construction Expenditures Included in Current Liabilities as of December 31,	71.2	41.8	92.9
Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent	0	0	(2)
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC	$ 0	$ 0	$ 2

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations (Applies to AEP) In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, Operating Agreement, Transmission Agreement and Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA and the Bridge Agreement, see Note 16 - Related Party Transactions for additional information. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries and Transition Funding (a substantially-controlled VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. AEP, AEP Texas, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Accounting for the Impacts of Tax Reform Given the significance of the legislative changes resulting from Tax Reform, the timing of its enactment and the widespread applicability to registrants, the SEC staff recognized the potential challenges faced by registrants when reflecting the effects of Tax Reform in their 2017 financial statements. Accordingly, the SEC staff issued Staff Accounting Bulletin 118 (SAB 118) in December 2017, which provides for a one year measurement period to complete the accounting for Tax Reform. The Registrants have made reasonable estimates for the measurement and accounting for the impacts of Tax Reform and these estimates are reflected in the December 31, 2017 financial statements as provisional amounts. While the Registrants were able to make reasonable estimates of the impact of Tax Reform, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative temporary differences or as a result of additional guidance or technical corrections that may be issued by the IRS or regulatory state commissions that impacts management’s interpretation and assumptions utilized. See “Federal Tax Reform” section of Note 12 for additional information. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Restricted Cash (Applies to AEP, AEP Texas, APCo and OPCo) Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds. Reconciliation of Cash, Cash Equivalents and Restricted Cash The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheet that sum to the total of the same amounts shown on the statement of cash flows: December 31, 2017 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 214.6 $ 2.0 $ 2.9 $ 3.1 Restricted Cash 198.0 155.2 16.3 26.6 Total Cash, Cash Equivalents and Restricted Cash $ 412.6 $ 157.2 $ 19.2 $ 29.7 December 31, 2016 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 210.5 $ 0.6 $ 2.7 $ 3.1 Restricted Cash 193.0 146.3 15.8 27.2 Total Cash, Cash Equivalents and Restricted Cash $ 403.5 $ 146.9 $ 18.5 $ 30.3 Other Temporary Investments (Applies to AEP) Other Temporary Investments include securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant customers which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31: Significant Customers of AEP Texas: Centrica, Just Energy and Reliant Energy 2017 (a) 2016 2015 Percentage of Total Revenues 35 % 46 % 53 % Percentage of Accounts Receivable – Customers 31 % 42 % 43 % (a) Just Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer. AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31: Significant Customers of AEPTCo: AEP Subsidiaries 2017 2016 2015 Percentage of Total Revenues 80 % 77 % 73 % Percentage of Total Accounts Receivable 82 % 86 % 77 % The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances and Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo) In regulated jurisdictions, the Registrants record emission allowances and renewable energy credits (RECs) at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances and RECs at the lower of cost or market. The Registrants follow the inventory model for these allowances and RECs. Allowances and RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances and RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances and RECs are reported in the Operating Activities section of the statements of cash flows. Allowances are consumed in the production of energy, and RECs are consumed to meet applicable state renewable portfolio standards and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenues on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances and RECs affects the determination of deferred fuel or deferred emission allowance and REC costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheet. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo) The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and 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 benefits and 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. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value. Deferred Fuel Costs (Applies to all Registrants except AEP Texas and AEPTCo) The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. In Ohio, changes in fuel costs and purchased power costs, incurred from 2009 through 2011, continue to be recovered in rider rates that will terminate in December 2018. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance s

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. During FASB’s standard-setting process and upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 changing the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, 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 analyzed 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. Additionally, the new standard did not give rise to any changes in current accounting systems. Management continues to develop disclosures to comply with the requirements of ASU 2014-09, including disclosures of significant disaggregated revenue streams, and information about fixed performance obligations that are unsatisfied (or partially unsatisfied) as of the end of a reporting period. Management adopted ASU 2014-09 effective January 1, 2018, by means of the modified retrospective approach. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. Management will continue to actively participate in informal industry forums throughout the period of initial adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 revising the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for certain provisions. Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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; however, the FASB is currently evaluating whether to provide reporting entities with an additional expedient to adopt the new lease requirements through a cumulative-effect adjustment in the period of adoption. Accordingly, management continues to monitor these standard-setting activities that may impact the transition requirements of the lease standard. 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 the process of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard to impact financial position and, at this time, cannot estimate the impact. Management expects no impact to results of operations or cash flows. Management continues to monitor unresolved industry implementation issues, including items related to easements and right-of-ways, and will analyze the related impacts to lease accounting. In this regard, to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease standard, the FASB issued ASU 2018-01 in January 2018. This ASU provides an optional transition practical expedient that allows companies to exclude in their evaluation of Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, which reduces the volume of contracts requiring evaluation. Management intends to elect this practical expedient upon adoption of ASU 2016-02. Management continues to monitor FASB’s ongoing standard-setting activities that may result in the issuance of additional targeted improvements to the new lease guidance. 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 previous 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. Management adopted ASU 2016-18 for the 2017 Annual Report and applied the new standard retrospectively for all periods presented. See the “Restricted Cash” section of Note 1 for the effect of adoption on cash flows for each Registrant. 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2017, AEP’s actual non-service cost components were a credit of $72 million , of which approximately 41% was capitalized. 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 adopted ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02) In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. Under existing accounting guidance for “Income Taxes”, deferred tax assets and liabilities must be adjusted for the effect of a change in tax laws or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI do not reflect the newly enacted corporate tax rate. While the reclassification between AOCI and Retained Earnings is optional under the new guidance, the ASU also requires certain new disclosure requirements regardless of whether the reclassification is made. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. The new guidance must be applied either retrospectively to each period (or periods) in which the income tax effects of Tax Reform related to items remaining in AOCI are recognized, or at the beginning of the period of adoption. Management is analyzing the impact of this new standard, including the possibility of early adoption.

Comprehensive Income

Comprehensive Income	12 Months Ended
	Dec. 31, 2017
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2017 , 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (20.4 ) 1.6 3.5 — 86.5 71.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — — (5.6 ) Purchased Electricity for Resale 28.8 — — — — 28.8 Interest Expense — 1.5 — — — 1.5 Amortization of Prior Service Cost (Credit) — — — (19.6 ) — (19.6 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 23.2 1.5 — 1.7 — 26.4 Income Tax (Expense) Credit 8.1 0.4 — 0.6 — 9.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 15.1 1.1 — 1.1 — 17.3 Net Current Period Other Comprehensive Income (Loss) (5.3 ) 2.7 3.5 1.1 86.5 88.5 Balance in AOCI as of December 31, 2017 $ (28.4 ) $ (13.0 ) $ 11.9 $ 141.6 $ (179.9 ) $ (67.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (5.4 ) $ 4.2 $ (13.7 ) $ (14.9 ) Change in Fair Value Recognized in AOCI — — 1.1 1.1 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains)/Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 0.4 — 1.7 Income Tax (Expense) Credit 0.4 0.1 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 0.3 — 1.2 Net Current Period Other Comprehensive Income (Loss) 0.9 0.3 1.1 2.3 Balance in AOCI as of December 31, 2017 $ (4.5 ) $ 4.5 $ (12.6 ) $ (12.6 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (6.5 ) $ 3.9 $ (14.6 ) $ (17.2 ) Change in Fair Value Recognized in AOCI (0.1 ) — 0.9 0.8 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.8 — — 1.8 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains)/Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 0.4 — 2.2 Income Tax (Expense) Credit 0.6 0.1 — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 0.3 — 1.5 Net Current Period Other Comprehensive Income (Loss) 1.1 0.3 0.9 2.3 Balance in AOCI as of December 31, 2016 $ (5.4 ) $ 4.2 $ (13.7 ) $ (14.9 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ (7.7 ) $ 3.6 $ (14.8 ) $ (18.9 ) Change in Fair Value Recognized in AOCI (0.1 ) — 0.2 0.1 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.9 — — 1.9 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains)/Losses — 0.6 — 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.9 0.5 — 2.4 Income Tax (Expense) Credit 0.6 0.2 — 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 0.3 — 1.6 Net Current Period Other Comprehensive Income (Loss) 1.2 0.3 0.2 1.7 Balance in AOCI as of December 31, 2015 $ (6.5 ) $ 3.9 $ (14.6 ) $ (17.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — 11.6 11.6 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — (5.2 ) — (5.2 ) Amortization of Actuarial (Gains)/Losses — 3.4 — 3.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) (1.8 ) — (2.9 ) Income Tax (Expense) Credit (0.4 ) (0.6 ) — (1.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.7 ) (1.2 ) — (1.9 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) (1.2 ) 11.6 9.7 Balance in AOCI as of December 31, 2017 $ 2.2 $ 14.8 $ (15.7 ) $ 1.3 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — 2.8 2.8 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 — — 2.0 Income Tax (Expense) Credit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) 1.3 — 2.8 4.1 Balance in AOCI as of December 31, 2017 $ (10.7 ) $ 5.1 $ (6.5 ) $ (12.1 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 — — 2.0 Income Tax (Expense) Credit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 — — 1.7 Income Tax (Expense) Credit 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Cash Flow Hedge - 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 (1.7 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.7 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.1 ) Net Current Period Other Comprehensive Income (Loss) (1.1 ) Balance in AOCI as of December 31, 2017 $ 1.9 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedge - 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 (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.9 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) Balance in AOCI as of December 31, 2016 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedge - Interest Rate (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) Income Tax (Expense) Credit (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) Balance in AOCI as of December 31, 2015 $ 4.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Cash Flow Hedge - 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2017 $ 2.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedge - 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 (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2016 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedge - Interest Rate (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2015 $ 4.2 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — 4.7 4.7 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.2 — — 2.2 Amortization of Prior Service Cost (Credit) — (2.0 ) — (2.0 ) Amortization of Actuarial (Gains)/Losses — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.2 (1.1 ) — 1.1 Income Tax (Expense) Credit 0.8 (0.4 ) — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.4 (0.7 ) — 0.7 Net Current Period Other Comprehensive Income (Loss) 1.4 (0.7 ) 4.7 5.4 Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 1.2 $ 0.8 $ (4.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 )

Rate Matters

Rate Matters	12 Months Ended
	Dec. 31, 2017
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. Impact of Tax Reform Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which will impact outstanding rate and regulatory matters. For details on the impact of Tax Reform, see Note 12 - Income Taxes. AEP Texas Rate Matters (Applies to AEP and AEP Texas) AEP Texas Interim Transmission and Distribution Rates As of December 31, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $763 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. In November 2017, the PUCT published a proposed rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The proposal would require AEP Texas to file for a comprehensive rate review no later than April 1, 2019. In January 2018, AEP Texas submitted comments on the rule proposing, among other changes, that its initial filing due date under the rule be changed from April 1, 2019 to May 1, 2019. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of December 31, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $123 million , inclusive of approximately $100 million of incremental storm expenses recorded as a regulatory asset related to Hurricane Harvey. As of December 31, 2017, AEP Texas has recorded approximately $133 million of capital expenditures related to Hurricane Harvey. Also, as of December 31, 2017, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset. The other named 2017 hurricanes did not have a material impact on AEP’s operations. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. In February 2018, legislation separately passed the Virginia House of Delegates and the Senate of Virginia and, if enacted and signed into law by the Governor in its present form, will: (a) require APCo to not recover $10 million of fuel expenses incurred after July 1, 2018, (b) reduce APCo’s base rates by $50 million annually, on an interim basis and subject to true-up, effective July 30, 2018 related to Tax Reform and (c) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform. APCo’s next base rate review in 2020 will now include a review of earnings for test years 2017-2019, with triennial reviews of APCo’s base rates and earnings thereafter instead of biennial reviews. The current VA legislative session is scheduled to adjourn in March 2018. Either a biennial review of 2018-2019 or a triennial review of 2017-2019 could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates AEP 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 December 31, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $746 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. In November 2017, the PUCT published a proposed rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The proposal requires ETT to file for a comprehensive rate review no later than February 1, 2021. In January 2018, ETT submitted comments recommending changes to the proposed draft rule. 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 a temporary 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 Plant Life Cycle Management Project. In November 2017, various intervenors filed testimony that included annual revenue increase recommendations ranging from $125 million to $152 million . The recommended returns on common equity ranged from 8.65% to 9.1% . In addition, certain parties recommended longer recovery periods than I&M proposed for recovery of regulatory assets and depreciation expenses related to Rockport Plant, Units 1 and 2. In January 2018, in response to a January 2018 IURC request related to the impact of Tax Reform on I&M’s pending base rate case, I&M filed updated schedules supporting a $191 million annual increase in Indiana base rates if the effect of Tax Reform was included in the cost of service. In February 2018, I&M and all parties to the case, except one industrial customer, filed a Stipulation and Settlement Agreement for a $97 million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures. The one industrial customer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily due to lower federal income taxes as a result of the reduction in the federal income tax rate due to Tax Reform, the feedback of credits for excess deferred income taxes, a 9.95% return on equity, longer recovery periods of regulatory assets, lower depreciation expense primarily for meters, and an increase in the sharing of off-system sales margins with customers from 50% to 95% . I&M will also refund $4 million from July through December 2018 for the impact of Tax Reform for the period January through June 2018. A hearing at the IURC is scheduled for March 2018. 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 April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed 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. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022), a reduced capacity charge and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, a market based capacity charge effective February 2019 for up to 10% of I&M’s Michigan customers, but did not address an annual net revenue increase. The intervenors’ recommended returns on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC was held in November 2017. In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million , including the intervenors’ proposed capacity charge and staff’s depreciation rates for Rockport Plant and a return on common equity of 9.8% . If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity charge is approximately $9 million . An order is expected in the first half of 2018. 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 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 December 31, 2017 , total costs incurred related to this project, including AFUDC, were approximately $23 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 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 motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2, which plaintiffs opposed. The district court has delayed the deadline for installation of the SCR technology until June 2020. In January 2018, I&M filed a supplemental motion with the U.S. District Court for the Southern District of Ohio proposing to install the SCR at Rockport Plant, Unit 2 and achieve the final SO 2 emission cap applicable to the plant under the consent decree by the end of 2020, before the expiration of the initial lease term. Responsive filings were filed in February 2018 and a decision is anticipated in the first quarter of 2018. 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 included: (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 Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, 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. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to lower interest expense related to June 2017 debt refinancings. In November 2017, KPCo filed a non-unanimous settlement agreement with the KPSC. The settlement agreement included a proposed annual base rate increase of $32 million based upon a 9.75% return on common equity. In January 2018, the KPSC issued an order approving the non-unanimous settlement agreement with certain modifications resulting in an annual revenue increase of $12 million , effective January 2018, based on a 9.7% return on equity. The KPSC’s primary revenue requirement modification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of $50 million of Rockport Plant Unit Power Agreement expenses for the years 2018 through 2022, with recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate case for three years and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life. In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million of annual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associated with forced outages and (c) capital structure adjustments. Also in February 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate, as a result of Tax Reform, be reflected in lower purchased power expense related to the Rockport UPA. It is anticipated that the KPSC will rule upon this rehearing request in the first quarter of 2018. 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 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 and 2016, the PUCO issued orders in this proceeding. As part of the issued orders, the PUCO approved (a) the DIR with modified rate caps, (b) recovery of OVEC-related net margin incurred beginning June 2016, (c) 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 (d) 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% 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) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO was held in November 2017. An order from the PUCO is expected in the first quarter of 2018. 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 that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (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. In January 2018, PUCO staff filed testimony that OPCo did not have significantly excessive earnings. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers. In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantly excessive earnings in 2016. In February 2018, a procedural schedule was issued by the PUCO. A hearing is scheduled for April 2018 and management expects to receive an order in the second quarter of 2018. While management believes that OPCo’s adjusted 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 proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group, 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 an increase in annual revenues of $156 million , less an $11 million refund obligation, for a net increase of $145 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 investments, (c) additional capital investments and 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, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of December 31, 2017 , the net book value of Northeastern Plant, Unit 4 was $81 million . In January 2018, the OCC issued a final order approving a net increase in Oklahoma annual revenues of $84 million , which was then reduced by $32 million to $52 million to account for changes as a result of Tax Reform, based upon a return on common equity of 9.3% . The final order also included approval for recovery, with a debt return for investors, of the net book value of Northeastern Plant Unit 4 and an annual depreciation expense increase of $19 million , including requested recovery through 2040 of Northeastern Plant, Unit 3. PSO anticipates implementing new rates in March 2018 billings. 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, SWEPCo reversed $114 million of previously recorded regulatory disallowances in 2013. The resulting annual base rate increase was approximately $52 million . In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. 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. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6% , effective May 2017. The final order also included (a) approval to recover the Texas jurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. As a result of the final order, in the fourth quarter, SWEPCo (a) recorded an impairment charge of $19 million , which includes $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that will be surcharged to customers and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expenses. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will be collected by the end of 2018. In addition, SWEPCo is required to file a refund tariff within 120 days to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. In January 2018, SWEPCo and the LPSC staff filed a settlement, subject to LPSC approval, providing for a $19 million pretax write off of the Louisiana jurisdictional share of previously capitalized Turk Plant costs and a $10 million rate refund provision for previously collected revenues associated with the disallowed portion of the Turk Plant. Based on the agreement, management concluded that the disallowance was probable resulting in a $23 million pretax write-off in the fourth quarter, consisting of a $15 million pretax impairment and an $8 million pretax provision for revenue refund. The agreement requires $2 million of the provision to be refunded to customers in the first billing cycle following LPSC approval of the settlement and the remaining $8 million to be amortized as a cost of service reduction for customers over 5 years, effective August 1, 2018. In February 2018, the LPSC approved the settlement agreement. 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. In February 2018, LPSC staff filed a report approving the increase as filed. This increase is subject to refund pending commission approval . 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 SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review. A hearing at the LPSC is scheduled for May 2018. 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 December 31, 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 December 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $627 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 April 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant, effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million , excluding $6 million of unrecognized equity as of December 31, 2017 , (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. In January 2018, SWEPCo received written approval from the PUCT to recover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” an

Effects of Regulation

Effects of Regulation	12 Months Ended
	Dec. 31, 2017
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2017 2016 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 203.1 $ 61.4 1 year Under-recovered Fuel Costs - does not earn a return 89.4 95.2 1 year Total Current Regulatory Assets $ 292.5 $ 156.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 159.9 Ohio Capacity Deferral — 96.7 Storm-Related Costs — 25.1 Other Regulatory Assets Pending Final Regulatory Approval 9.6 10.4 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 128.0 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 39.7 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects — 24.1 Cook Plant Turbine 15.9 12.8 Other Regulatory Assets Pending Final Regulatory Approval 42.2 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) 322.0 450.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (c) 682.6 550.6 27 years Ohio Capacity Deferral 172.6 201.9 2 years Basic Transmission Cost Rider 90.8 19.9 2 years Meter Replacement Costs 83.7 99.9 10 years Ohio Distribution Decoupling 61.7 41.8 2 years Storm-Related Costs 39.3 15.3 4 years Plant Retirement Costs - Asset Retirement Obligation Costs 34.3 18.3 23 years Advanced Metering System 33.5 20.9 3 years Environmental Control Projects 28.1 — 23 years Mitchell Plant Transfer 17.8 18.5 23 years West Virginia Delayed Customer Billing 8.4 19.5 1 year Ohio Phase-In Recovery Rider — 218.9 Other Regulatory Assets Approved for Recovery 41.0 55.4 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,196.3 1,516.2 12 years Unrealized Loss on Forward Commitments 139.3 119.1 15 years Unamortized Loss on Reacquired Debt 129.9 137.8 28 years Cook Plant Nuclear Refueling Outage Levelization 66.7 75.2 2 years Deferred PJM Fees 48.0 — 2 years Storm-Related Costs 44.2 58.7 6 years Peak Demand Reduction/Energy Efficiency 40.1 49.9 3 years Postemployment Benefits 39.1 39.1 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 48.9 23 years Vegetation Management 33.5 31.4 7 years Virginia Transmission Rate Adjustment Clause 32.6 38.7 2 years Medicare Subsidy 32.5 37.2 7 years Off-system Sales Margin Sharing - Indiana 9.0 24.3 2 years United Mine Workers of America Pension Withdrawal 0.5 20.2 5 years Income Taxes, Net — 1,575.0 OVEC Purchased Power — 22.1 Other Regulatory Assets Approved for Recovery 122.9 100.7 various Total Regulatory Assets Approved for Recovery 3,265.6 5,175.4 Total Noncurrent Regulatory Assets $ 3,587.6 $ 5,625.5 (a) As of December 31, 2017, AEP Texas has deferred $100 million related to Hurricane Harvey and is currently exploring recovery options. (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. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. (c) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of December 31, 2017 the unrecovered plant balance related to Northeastern Plant, Unit 3 was $57 million . AEP December 31, Remaining 2017 2016 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 8.7 $ 3.8 1 year Over-recovered Fuel Costs - does not pay a return 3.2 4.2 1 year Total Current Regulatory Liabilities $ 11.9 $ 8.0 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 4,412.8 $ — Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.8 Total Regulatory Liabilities Pending Final Regulatory Determination 4,413.0 0.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (b) 2,637.1 2,627.5 (c) Advanced Metering Infrastructure Surcharge 12.7 17.0 3 years Deferred Investment Tax Credits 10.6 12.6 41 years Excess Earnings 9.4 10.0 36 years Louisiana Refundable Construction Financing Costs — 16.2 Other Regulatory Liabilities Approved for Payment 1.3 1.6 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 945.0 731.2 (d) Deferred Investment Tax Credits 191.2 132.9 45 years Transition Charges 46.0 40.5 10 years Spent Nuclear Fuel 43.2 44.2 (d) Enhanced Service Reliability Plan 30.6 21.7 2 years Peak Demand Reduction/Energy Efficiency 25.6 34.0 2 years Other Regulatory Liabilities Approved for Payment 56.6 61.1 various Total Regulatory Liabilities Approved for Payment 4,009.3 3,750.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,422.3 $ 3,751.3 (a) This balance primarily represents regulatory liabilities for excess accumulated deferred income taxes (Excess ADIT) as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) As of December 31, 2017, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (c) Relieved as removal costs are incurred. (d) Relieved when plant is decommissioned. AEP Texas December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm-Related Costs $ — $ 25.1 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 123.3 — Rate Case Expense 0.1 0.1 Total Regulatory Assets Pending Final Regulatory Approval 123.4 25.2 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 44.9 49.8 10 years Advanced Metering System 33.5 21.3 3 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 151.2 188.2 12 years Transmission Cost Recovery Factor 9.5 5.3 1 year Unamortized Loss on Reacquired Debt 7.7 7.3 20 years Income Taxes, Net — 40.3 Other Regulatory Assets Approved for Recovery 8.5 9.8 various Total Regulatory Assets Approved for Recovery 255.3 322.0 Total Noncurrent Regulatory Assets $ 378.7 $ 347.2 (a) As of December 31, 2017, AEP Texas has deferred $100 million related to Hurricane Harvey and is currently exploring recovery options. AEP Texas December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 642.9 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 642.9 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 599.2 581.7 (b) Advanced Metering Infrastructure Surcharge 12.7 17.0 3 years Excess Earnings 6.8 7.3 14 years Regulatory Liabilities Currently Not Paying a Return Transition Charges 46.0 40.5 10 years Deferred Investment Tax Credits 12.3 13.9 45 years Other Regulatory Liabilities Approved for Payment 0.6 0.4 various Total Regulatory Liabilities Approved for Payment 677.6 660.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,320.5 $ 660.8 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. AEPTCo December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Noncurrent Regulatory Assets Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Income Taxes, Net $ — $ 106.1 Under-Recovered SPP Revenues — 1.6 Regulatory Assets Currently Not Earning a Return Under-Recovered OATT Costs 11.7 4.6 1 year Total Regulatory Assets Approved for Recovery 11.7 112.3 Total Noncurrent Regulatory Assets $ 11.7 $ 112.3 AEPTCo December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Noncurrent Regulatory Liabilities Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 427.0 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 427.0 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 66.7 44.0 (b) Total Regulatory Liabilities Approved for Payment 66.7 44.0 Total Noncurrent Regulatory Liabilities $ 493.7 $ 44.0 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. APCo December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 21.4 $ 6.2 1 year Under-recovered Fuel Costs - does not earn a return 67.4 62.2 1 year Total Current Regulatory Assets $ 88.8 $ 68.4 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: 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 39.7 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) 49.4 39.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 86.3 85.4 26 years West Virginia Delayed Customer Billing 7.8 18.1 1 year Other Regulatory Assets Approved for Recovery 3.9 6.8 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 168.8 221.4 12 years Unamortized Loss on Reacquired Debt 93.2 97.2 28 years Vegetation Management Program - West Virginia 33.5 31.4 7 years Virginia Transmission Rate Adjustment Clause 32.6 38.7 2 years Storm-Related Costs - West Virginia 32.2 47.8 3 years Postemployment Benefits 18.8 17.4 5 years Peak Demand Reduction/Energy Efficiency 18.1 19.2 3 years Virginia Generation Rate Adjustment Clause 7.3 6.5 2 years Income Taxes, Net — 463.5 Other Regulatory Assets Approved for Recovery 22.0 28.4 various Total Regulatory Assets Approved for Recovery 524.5 1,081.8 Total Noncurrent Regulatory Assets $ 573.9 $ 1,121.1 (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. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 820.3 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 820.3 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 615.8 616.9 (b) Deferred Investment Tax Credits 0.9 0.9 41 years Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 9.5 1.3 7 years Consumer Rate Relief - West Virginia 6.5 5.1 1 year Other Regulatory Liabilities Approved for Payment 1.9 3.6 various Total Regulatory Liabilities Approved for Payment 634.6 627.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,454.9 $ 627.8 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 15.0 $ 13.0 1 year Under-recovered Fuel Costs - does not earn a return — 13.1 Total Current Regulatory Assets $ 15.0 $ 26.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 15.9 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 14.7 8.1 Rockport Plant Dry Sorbent Injection System - Indiana 10.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 2.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval 79.3 64.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 245.3 252.8 27 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.0 6.3 21 years Other Regulatory Assets Approved for Recovery 1.0 2.5 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 77.8 141.9 12 years Cook Plant Nuclear Refueling Outage Levelization 66.7 75.2 2 years Deferred PJM Fees 48.0 — 2 years Postemployment Benefits 9.7 11.4 5 years Unamortized Loss on Reacquired Debt 9.5 10.7 15 years Off-system Sales Margin Sharing - Indiana 9.0 24.3 2 years Medicare Subsidy 7.1 8.2 7 years Income Taxes, Net — 302.6 Other Regulatory Assets Approved for Recovery 20.0 16.0 various Total Regulatory Assets Approved for Recovery 500.1 851.9 Total Noncurrent Regulatory Assets $ 579.4 $ 916.6 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 2.7 $ — 1 year Total Current Regulatory Liabilities $ 2.7 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 472.7 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 472.7 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (b) 202.2 236.5 (c) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 945.0 731.2 (d) Spent Nuclear Fuel 43.2 44.2 (d) Deferred Investment Tax Credits 34.1 38.8 20 years Other Regulatory Liabilities Approved for Payment 11.5 14.8 various Total Regulatory Liabilities Approved for Payment 1,236.0 1,065.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,708.7 $ 1,065.5 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) As of December 31, 2017, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (c) Relieved as removal costs are incurred. (d) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return (a) $ 115.9 $ — 1 year Total Current Regulatory Assets $ 115.9 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 (b) Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval — 100.8 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 172.6 201.9 2 years Basic Transmission Cost Rider 90.8 19.9 2 years Distribution Decoupling 61.7 41.8 2 years Phase-In Recovery Rider — 218.9 Other Regulatory Assets Approved for Recovery 1.7 4.2 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 170.6 225.2 12 years Unrealized Loss on Forward Commitments 131.8 118.6 15 years Unamortized Loss on Reacquired Debt 7.8 9.1 21 years Income Taxes, Net — 126.4 OVEC Purchased Power — 22.1 Other Regulatory Assets Approved for Recovery 15.8 18.6 various Total Regulatory Assets Approved for Recovery 652.8 1,006.7 Total Noncurrent Regulatory Assets $ 652.8 $ 1,107.5 (a) December 31, 2017 balance includes Phase-In Recovery Rider. (b) Capacity Deferral related to 2016 Global Settlement was approved for recovery effective March 2017. OPCo December 31, Remaining Refund Period 2017 2016 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ — $ 4.2 Total Current Regulatory Liabilities $ — $ 4.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 604.2 $ — Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 604.4 0.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 428.8 432.4 (b) Other Regulatory Liabilities Approved for Payment 1.4 0.3 various Regulatory Liabilities Currently Not Paying a Return Enhanced Service Reliability Plan 30.6 21.7 2 years Peak Demand Reduction/Energy Efficiency 23.6 29.0 2 years Smart Grid Costs 1.4 11.9 1 year Other Regulatory Liabilities Approved for Payment 10.0 10.7 various Total Regulatory Liabilities Approved for Payment 495.8 506.0 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,100.2 $ 506.2 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2017 2016 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 36.7 $ 33.8 1 year Total Current Regulatory Assets $ 36.7 $ 33.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ — $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval — 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 3.2 20.0 Environmental Control Projects — 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Total Regulatory Assets Pending Final Regulatory Approval 3.3 118.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) 138.5 — 23 years Storm-Related Costs 39.0 10.8 4 years Meter Replacement Costs 38.8 50.1 7 years Environmental Control Projects 28.1 — 23 years Red Rock Generating Facility 8.8 9.1 39 years Other Regulatory Assets Approved for Recovery 0.5 — various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 72.7 98.1 12 years SPP Base Plan Fees 16.3 10.7 2 years Peak Demand Reduction/Energy Efficiency 13.0 10.3 2 years Unamortized Loss on Reacquired Debt 5.0 5.8 15 years Deferred System Reliability Rider Expenses — 12.5 Income Taxes, Net — 9.3 Other Regulatory Assets Approved for Recovery 4.1 5.4 various Total Regulatory Assets Approved for Recovery 364.8 222.1 Total Noncurrent Regulatory Assets $ 368.1 $ 340.2 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of December 31, 2017 the unrecovered plant balance related to Northeastern Plant, Unit 3 was $57 million . PSO December 31, Remaining Refund Period 2017 2016 Regulatory Liabilities: (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 531.7 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 531.7 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 268.8 279.3 (b) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 50.7 48.0 41 years Advanced Metering Costs 0.6 11.5 1 year Other Regulatory Liabilities Approved for Payment 1.7 0.9 various Total Regulatory Liabilities Approved for Payment 321.8 339.7 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 853.5 $ 339.7 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2017 2016 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 14.1 $ 8.4 1 year Total Current Regulatory Assets $ 14.1 $ 8.4 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.3 1.0 Asset Retirement Obligation - Arkansas, Louisiana 4.0 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Controls Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.5 1.9 Total Regulatory Assets Pending Final Regulatory Approval 64.9 95.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 7.2 1.3 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 101.0 119.8 12 years Plant Retirement Costs - Unrecovered Plant 17.6 — 24 years Environmental Controls Projects 15.3 — 15 years Unamortized Loss on Reacquired Debt 4.7 5.4 26 years Medicare Subsidy 3.7 4.3 7 years Income Taxes, Net — 314.2 Other Regulatory Assets Approved for Recovery 6.2 10.3 various Total Regulatory Assets Approved for Recovery 155.7 455.3 Total Noncurrent Regulatory Assets $ 220.6 $ 551.2 SWEPCo December 31, Remaining Refund Period 2017 2016 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.7 $ 3.8 1 year Total Current Regulatory Liabilities $ 8.7 $ 3.8 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 455.9 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 455.9 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 424.5 409.7 (b) Refundable Construction Financing Costs - Louisiana — 16.2 Other Regulatory Liabilities Approved for Payment 2.6 3.9 various Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 5.9 7.3 14 years Other Regulatory Liabilities Approved for Payment 7.5 1.8 various Total Regulatory Liabilities Approved for Payment 440.5 438.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 896.4 $ 438.9 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred.

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 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. COMMITMENTS (Applies to all Registrants except AEP Texas and AEPTCo) The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2017 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 1,067.6 $ 1,019.5 $ 544.9 $ 221.6 $ 2,853.6 Energy and Capacity Purchase Contracts 230.1 456.1 378.0 1,467.3 2,531.5 Total $ 1,297.7 $ 1,475.6 $ 922.9 $ 1,688.9 $ 5,385.1 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 369.1 $ 364.4 $ 165.2 $ 0.9 $ 899.6 Energy and Capacity Purchase Contracts 36.0 72.3 72.9 354.9 536.1 Total $ 405.1 $ 436.7 $ 238.1 $ 355.8 $ 1,435.7 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 236.9 $ 269.4 $ 204.6 $ 166.6 $ 877.5 Energy and Capacity Purchase Contracts 125.4 255.9 259.9 352.4 993.6 Total $ 362.3 $ 525.3 $ 464.5 $ 519.0 $ 1,871.1 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 29.9 $ 59.3 $ 58.4 $ 363.7 $ 511.3 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 45.9 $ 71.7 $ 30.5 $ — $ 148.1 Energy and Capacity Purchase Contracts 91.5 181.5 127.8 236.8 637.6 Total $ 137.4 $ 253.2 $ 158.3 $ 236.8 $ 785.7 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 111.7 $ 85.8 $ 55.4 $ — $ 252.9 Energy and Capacity Purchase Contracts 33.0 67.3 53.4 151.0 304.7 Total $ 144.7 $ 153.1 $ 108.8 $ 151.0 $ 557.6 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. 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, AEP Texas 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. As of December 31, 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 $345 million . In October 2017, a $100 million uncommitted facility expired. As of December 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 103.5 January 2018 to December 2018 AEP Texas 2.8 January 2018 OPCo 0.6 September 2018 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 approximately $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2017 , SWEPCo has collected approximately $72 million through a rider for final mine closure and reclamation costs, of which $76 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 December 31, 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 December 31, 2017 , there were no material liabilities recorded for any indemnifications. AEPSC conducts power purchase and sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase and sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES (Applies to All Registrants except AEPTCo) 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2017 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are eleven additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 completed remediation work in 2015 and 2017, I&M’s accrual was reduced. As of December 31, 2017 , I&M’s accrual for all of these sites is $100 thousand . The remediation work is expected to be completed in 2018. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites. 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 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. 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 January 2018, Westinghouse issued a news release stating that it intends to sell all of its global business, including the portion of the nuclear business that contracts with Cook Plant. Any sale would require approval by the bankruptcy court. In the unlikely event Westinghouse rejects I&M’s contracts, or there is an interference with the sale process, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2017 and 2016 , the total decommissioning trust fund balance was $2.2 billion and $1.9 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2017 and 2016 , fees and related interest of $269 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $312 million and $311 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $22 million , $6 million and $13 million in 2017 , 2016 and 2015 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2017 , I&M has deferred $11 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $51 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $450 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $450 million through commercially available insurance. The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. 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 and remanding 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. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, 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. In November 2017, the district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. 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. 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 has settled, received summary judgment or was dismissed from all of these cases in 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. 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.

Dispositions, Assets and Liabil

Dispositions, Assets and Liabilities Held for Sale and Impairments	12 Months Ended
	Dec. 31, 2017
Impairments, Disposition and Assets and Liabilities Held for Sale	DISPOSITIONS, ASSETS AND LIABILITIES HELD FOR SALE AND IMPAIRMENTS The disclosures in this note apply to AEP unless indicated otherwise. DISPOSITIONS 2017 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 years ended December 31, 2017, 2016, and 2015. 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 for the year ended December 31, 2017 . 2016 Tanners Creek Plant (Vertically Integrated Utilities Segment) (Applies to AEP and I&M) In October 2016, I&M sold its retired Tanners Creek Plant site including its associated asset retirement obligations (AROs) to a nonaffiliated party. I&M paid $92 million and the nonaffiliated party took ownership of the Tanners Creek plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. I&M did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners Creek are not recoverable, it could reduce future net income and impact financial condition. Wind Farms (Applies to AEP Texas) In December 2016, TCC and TNC merged into AEP Utilities, Inc. Prior to the merger, AEP Utilities, Inc. was a subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc. CSW Energy, Inc. owns the Desert Sky and Trent Wind Farms (“Wind Farms”). Upon merger, AEP Utilities, Inc. changed its name to AEP Texas. Subsequent to the merger, AEP Texas exited the merchant generation business by transferring all of the common stock of the Wind Farms to a competitive AEP affiliate. No gain or loss was recognized and no cash was exchanged related to the disposition of the Wind Farms. In the fourth quarter of 2016, the Wind Farms were determined to be discontinued operations. Accordingly, results of operations of the Wind Farms have been classified as discontinued operations on AEP Texas’ statements of income for the years ended December 31, 2016 and 2015 as shown in the following table: AEP Texas Years Ended December 31, 2016 2015 (in millions) Revenue $ 18.2 $ 22.4 Other Operation Expense 6.5 6.5 Maintenance Expense 3.4 4.9 Asset Impairment and Other Related Charges 72.7 — Depreciation and Amortization Expense 9.8 11.5 Taxes Other Than Income Taxes 1.3 1.3 Total Expenses 93.7 24.2 Other Income (Expense) (0.8 ) (1.3 ) Pretax Income of Discontinued Operations (76.3 ) (3.1 ) Income Tax Expense (27.5 ) (1.7 ) Total Income on Discontinued Operations as Presented on the Statements of Income $ (48.8 ) $ (1.4 ) 2015 Muskingum River Plant (Generation & Marketing Segment) In August 2015, AGR sold its retired Muskingum River Plant site including its associated asset retirement obligations to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statements of income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in International Marine Terminals, LLC, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statement of income for the year ended December 31, 2015 , as shown in the following table: Corporate and Other Years Ended December 31, 2015 (in millions) Other Revenues $ 447.1 Other Operation Expense 321.3 Maintenance Expense 21.5 Depreciation and Amortization Expense 26.9 Taxes Other Than Income Taxes 10.6 Total Expenses 380.3 Other Income (Expense) (16.9 ) Pretax Income of Discontinued Operations 49.9 Income Tax Expense 19.4 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) Income from Discontinued Operations of AEPRO 30.4 Gain on Sale of Discontinued Operations 240.1 Income Tax Expense (Benefit) (13.2 ) Gain on Sale of Discontinued Operations, Net of Tax 253.3 Total Income on Discontinued Operations as Presented on the Statement of Income $ 283.7 In the second quarter of 2016, AEP recorded a $3 million loss related to the final accounting for the sale of AEPRO, which was recorded in Income (Loss) from Discontinued Operations, Net of Tax, on AEP’s statements of income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In the third quarter of 2016, management determined the Gavin, Waterford, Darby and Lawrenceburg Plants met the classification of held for sale. Accordingly, the four plants’ assets and liabilities were 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 $375 million and $451 million for the years ended December 31, 2016 and 2015 , respectively. Generation & Marketing Segment December 31, 2016 Assets: (in millions) 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 Sheet $ 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 Sheet $ 235.9 IMPAIRMENTS 2017 Merchant Generating Assets (Generation & Marketing Segment) Through the third 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. The initial impairment recorded related to these assets is discussed in the “2016” section below. In addition, AEP recorded a $7 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. Due to a significant increase in estimated costs identified in December 2017 to repair a defective dam structure at Racine Hydroelectric Plant (“Racine”), AEP performed an impairment analysis on Racine in accordance with accounting guidance for impairments of long-lived assets. AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful life of Racine based upon energy and capacity price curves, which were developed internally with both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. AEP performed step two of the impairment analysis on Racine using a ten-year discounted cash flow model based upon similar forecasted information used in the step one test. The step two analysis resulted in a fair value determination for Racine of $0 and AEP recorded a pretax impairment of $43 million in Assets Impairments and Other Related Charges on the statement of income in the fourth quarter of 2017. Welsh Plant, Unit 2 and Turk Plant (Vertically Integrated Utilities Segment) (Applies to AEP and SWEPCo) In December 2017, SWEPCo recorded a pretax impairment of $19 million in Asset Impairments and Other Related Charges on the statements of income related to the Texas jurisdictional share of Welsh Plant, Unit 2 and other disallowed plant investments. Additionally in December 2017, SWEPCo recorded a pretax impairment of $15 million in Asset Impairments and Other Related Charges on the statements of income related to the Louisiana jurisdictional share of the Turk Plant. See the “2016 Texas Base Rate Case” and “Louisiana Turk Plant Prudence Review” sections of Note 4 . 2016 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. Cardinal, Unit 1, a 43.5% interest in Conesville, Unit 4, Conesville, Units 5 and 6, a 26% interest in Stuart, Units 1-4, a 25.4% interest in Zimmer, Unit 1, and a 54.7% interest in Oklaunion (collectively the “Merchant Coal-Fired Generation Assets”) were subject to this analysis. Additionally, Racine, Putnam and I&M’s Price River coal reserves (“Coal Reserves”) and the Wind Farms were also included in this analysis. For the Merchant Coal-Fired Generation Assets, Racine and the Wind Farms, AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful lives of the assets based upon energy and capacity price curves, as applicable, which were developed internally with both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step one analysis concluded the book value of Racine would be recovered and the book value of the remaining assets would not be recovered. AEP performed step two of the impairment analysis on the Merchant Coal-Fired Generation Assets using a ten-year discounted cash flow model based upon forecasted energy and capacity price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step two analysis resulted in projected negative cash flows. Based on this result, coupled with the significant capital investments necessary to comply with environmental rules to allow the Merchant Coal-Fired Generation Assets to operate to the end of their currently estimated depreciable lives and the joint-ownership structure of these facilities, management determined the fair value of these assets was $0. AEP performed step two of the impairment analysis on the Wind Farms using a ten-year discounted cash flow model utilizing forecasted energy price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The results concluded the Wind Farms were also impaired. For the Coal Reserves, AEP performed step one of the impairment analysis and concluded the book value of the assets would not be recovered. Step two of the impairment analysis on the Coal Reserves was performed using a market approach with Level 3 unobservable inputs. The results concluded the Coal Reserves were also impaired. Based on the impairment analysis performed, in the third quarter of 2016, AEP recorded a pretax impairment of $2.3 billion in Asset Impairments and Other Related Charges on the statements of income. See the table below for additional information. Impaired Assets Book Value Fair Value Impairment (in millions) Merchant Coal-Fired Generation Assets $ 2,139.4 $ — $ 2,139.4 Trent and Desert Sky Wind Farms 118.7 46.0 72.7 Coal Reserves (a) 56.6 3.8 52.8 Total $ 2,314.7 $ 49.8 $ 2,264.9 (a) Includes the $11 million book value of I&M’s Price River Coal Reserves which were fully impaired. This $11 million impairment is reflected in the Vertically Integrated Utilities Segment. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statement of income.

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2017
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans OPEB December 31, Assumption 2017 2016 2017 2016 Discount Rate 3.65 % 4.05 % 3.60 % 4.10 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2017 2016 AEP 4.80 % 4.75 % AEP Texas 4.90 % 4.85 % APCo 4.60 % 4.55 % I&M 4.85 % 4.80 % OPCo 4.95 % 4.85 % PSO 4.90 % 4.90 % SWEPCo 4.80 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2017 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans OPEB Year Ended December 31, Assumptions 2017 2016 2015 2017 2016 2015 Discount Rate 4.05 % 4.30 % 4.00 % 4.10 % 4.30 % 4.00 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 6.75 % 7.00 % 6.75 % Pension Plans Year Ended December 31, Assumption – Rate of Compensation Increase (a) 2017 2016 2015 AEP 4.80 % 4.75 % 4.80 % AEP Texas 4.90 % 4.85 % 4.50 % APCo 4.60 % 4.55 % 4.45 % I&M 4.85 % 4.80 % 4.80 % OPCo 4.95 % 4.85 % 4.80 % PSO 4.90 % 4.90 % 4.80 % SWEPCo 4.80 % 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: December 31, Health Care Trend Rates 2017 2016 Initial 6.50 % 7.00 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2024 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 2.5 $ 0.1 $ 0.5 $ 0.2 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.0 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 45.4 $ 2.6 $ 10.8 $ 3.7 $ 3.5 $ 1.7 $ 1.9 1% Decrease (39.6 ) (2.4 ) (9.1 ) (3.4 ) (3.2 ) (1.5 ) (1.8 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2017 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Service Cost 96.5 85.8 11.2 10.2 Interest Cost 203.1 211.6 59.3 60.9 Actuarial (Gain) Loss 182.4 142.7 (97.5 ) 17.3 Benefit Payments (352.0 ) (347.2 ) (128.6 ) (130.2 ) Participant Contributions — — 39.5 37.8 Medicare Subsidy — — 0.7 0.8 Benefit Obligation as of December 31, $ 5,215.8 $ 5,085.8 $ 1,332.0 $ 1,447.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Actual Gain on Plan Assets 600.0 315.5 271.6 56.0 Company Contributions 98.8 91.4 4.1 4.9 Participant Contributions — — 39.5 37.8 Benefit Payments (352.0 ) (347.2 ) (128.6 ) (130.2 ) Fair Value of Plan Assets as of December 31, $ 5,174.1 $ 4,827.3 $ 1,732.5 $ 1,545.9 Funded (Underfunded) Status as of December 31, $ (41.7 ) $ (258.5 ) $ 400.5 $ 98.5 AEP Texas Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 421.7 $ 420.3 $ 120.4 $ 122.0 Transfer of CSW Energy, Inc. Benefit Obligation — (2.8 ) — (0.4 ) Service Cost 8.6 7.5 0.9 0.7 Interest Cost 17.1 17.8 4.9 5.1 Actuarial (Gain) Loss 25.6 11.1 (11.9 ) 0.8 Benefit Payments (31.7 ) (32.2 ) (10.8 ) (11.4 ) Participant Contributions — — 3.6 3.5 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 441.3 $ 421.7 $ 107.1 $ 120.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 416.6 $ 415.4 $ 134.1 $ 138.6 Transfer of CSW Energy, Inc. Plan Assets — (2.5 ) — (0.4 ) Actual Gain on Plan Assets 61.8 27.4 20.4 3.8 Company Contributions 9.2 8.5 — — Participant Contributions — — 3.6 3.5 Benefit Payments (31.7 ) (32.2 ) (10.8 ) (11.4 ) Fair Value of Plan Assets as of December 31, $ 455.9 $ 416.6 $ 147.3 $ 134.1 Funded (Underfunded) Status as of December 31, $ 14.6 $ (5.1 ) $ 40.2 $ 13.7 APCo Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Service Cost 9.4 8.1 1.1 1.0 Interest Cost 25.7 27.2 10.6 10.8 Actuarial (Gain) Loss 15.7 9.2 (13.4 ) (0.2 ) Benefit Payments (39.8 ) (43.9 ) (24.3 ) (24.8 ) Participant Contributions — — 6.7 6.4 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 665.0 $ 654.0 $ 236.5 $ 255.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Actual Gain on Plan Assets 74.9 38.3 41.6 5.9 Company Contributions 10.2 8.8 2.5 2.7 Participant Contributions — — 6.7 6.4 Benefit Payments (39.8 ) (43.9 ) (24.3 ) (24.8 ) Fair Value of Plan Assets as of December 31, $ 651.7 $ 606.4 $ 273.4 $ 246.9 Funded (Underfunded) Status as of December 31, $ (13.3 ) $ (47.6 ) $ 36.9 $ (8.7 ) I&M Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Service Cost 14.0 12.2 1.6 1.5 Interest Cost 24.3 25.3 6.9 7.0 Actuarial (Gain) Loss 10.8 20.1 (12.0 ) 3.8 Benefit Payments (36.4 ) (37.5 ) (15.6 ) (15.7 ) Participant Contributions — — 4.9 4.6 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 624.3 $ 611.6 $ 153.5 $ 167.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Actual Gain on Plan Assets 74.0 40.6 35.2 8.7 Company Contributions 13.0 13.0 — — Participant Contributions — — 4.9 4.6 Benefit Payments (36.4 ) (37.5 ) (15.6 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 636.7 $ 586.1 $ 211.1 $ 186.6 Funded (Underfunded) Status as of December 31, $ 12.4 $ (25.5 ) $ 57.6 $ 19.0 OPCo Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Service Cost 7.5 6.5 0.9 0.8 Interest Cost 19.4 20.6 6.7 7.0 Actuarial (Gain) Loss 13.1 4.7 (16.6 ) (1.0 ) Benefit Payments (31.8 ) (36.4 ) (15.5 ) (16.2 ) Participant Contributions — — 4.7 4.7 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 501.1 $ 492.9 $ 144.3 $ 164.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Actual Gain on Plan Assets 58.9 30.9 26.7 2.5 Company Contributions 8.2 7.2 — — Participant Contributions — — 4.7 4.7 Benefit Payments (31.8 ) (36.4 ) (15.5 ) (16.2 ) Fair Value of Plan Assets as of December 31, $ 509.1 $ 473.8 $ 198.5 $ 182.6 Funded (Underfunded) Status as of December 31, $ 8.0 $ (19.1 ) $ 54.2 $ 18.6 PSO Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Service Cost 6.4 6.2 0.7 0.6 Interest Cost 10.7 11.2 3.2 3.3 Actuarial (Gain) Loss 10.1 3.1 (7.5 ) 1.0 Benefit Payments (17.3 ) (19.2 ) (6.9 ) (7.2 ) Participant Contributions — — 2.3 2.2 Benefit Obligation as of December 31, $ 276.6 $ 266.7 $ 69.4 $ 77.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Actual Gain on Plan Assets 33.6 17.3 13.7 3.1 Company Contributions 5.5 5.8 — — Participant Contributions — — 2.3 2.2 Benefit Payments (17.3 ) (19.2 ) (6.9 ) (7.2 ) Fair Value of Plan Assets as of December 31, $ 287.8 $ 266.0 $ 95.5 $ 86.4 Funded (Underfunded) Status as of December 31, $ 11.2 $ (0.7 ) $ 26.1 $ 8.8 SWEPCo Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Service Cost 8.7 8.1 0.9 0.8 Interest Cost 12.3 12.4 3.6 3.6 Actuarial (Gain) Loss 16.3 13.8 (6.2 ) 1.5 Benefit Payments (19.3 ) (20.5 ) (7.4 ) (7.5 ) Participant Contributions — — 2.5 2.4 Benefit Obligation as of December 31, $ 314.6 $ 296.6 $ 80.3 $ 86.9 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Actual Gain on Plan Assets 34.6 18.8 18.5 4.1 Company Contributions 9.1 8.4 — — Participant Contributions — — 2.5 2.4 Benefit Payments (19.3 ) (20.5 ) (7.4 ) (7.5 ) Fair Value of Plan Assets as of December 31, $ 311.7 $ 287.3 $ 110.4 $ 96.8 Funded (Underfunded) Status as of December 31, $ (2.9 ) $ (9.3 ) $ 30.1 $ 9.9 Amounts Recognized on the Balance Sheets Pension Plans OPEB December 31, AEP 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 36.3 $ — $ 463.0 $ 154.5 Other Current Liabilities – Accrued Short-term Benefit Liability (6.2 ) (5.9 ) (3.2 ) (3.0 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (71.8 ) (252.6 ) (59.3 ) (53.0 ) Funded (Underfunded) Status $ (41.7 ) $ (258.5 ) $ 400.5 $ 98.5 Pension Plans OPEB December 31, AEP Texas 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 18.6 $ — $ 40.2 $ 13.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.4 ) (0.4 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (3.6 ) (4.7 ) — — Funded (Underfunded) Status $ 14.6 $ (5.1 ) $ 40.2 $ 13.7 Pension Plans OPEB December 31, APCo 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 74.6 $ 25.2 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.5 ) (2.4 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (13.3 ) (47.6 ) (35.2 ) (31.5 ) Funded (Underfunded) Status $ (13.3 ) $ (47.6 ) $ 36.9 $ (8.7 ) Pension Plans OPEB December 31, I&M 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 13.4 $ — $ 57.6 $ 19.0 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.0 ) (25.5 ) — — Funded (Underfunded) Status $ 12.4 $ (25.5 ) $ 57.6 $ 19.0 Pension Plans OPEB December 31, OPCo 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 8.4 $ — $ 54.2 $ 18.6 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (0.4 ) (19.1 ) — — Funded (Underfunded) Status $ 8.0 $ (19.1 ) $ 54.2 $ 18.6 Pension Plans OPEB December 31, PSO 2017 2016 2017 2016 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 13.9 $ 1.6 $ 26.1 $ 8.8 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (2.5 ) (2.1 ) — — Funded (Underfunded) Status $ 11.2 $ (0.7 ) $ 26.1 $ 8.8 Pension Plans OPEB December 31, SWEPCo 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.1 $ 9.9 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.7 ) (9.2 ) — — Funded (Underfunded) Status $ (2.9 ) $ (9.3 ) $ 30.1 $ 9.9 Amounts Included in AOCI, Income Tax Expense and Regulatory Assets AEP Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 1,354.2 $ 1,569.8 $ 309.9 $ 614.4 Prior Service Cost (Credit) — 1.0 (416.3 ) (485.4 ) Recorded as Regulatory Assets $ 1,271.3 $ 1,415.6 $ (82.4 ) $ 90.4 Deferred Income Taxes 17.4 54.4 (5.0 ) 13.5 Net of Tax AOCI 53.9 100.8 (15.6 ) 25.1 Income Tax Expense (a) 11.6 — (3.4 ) — AEP Texas Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 175.2 $ 193.3 $ 23.9 $ 50.7 Prior Service Credit — — (35.4 ) (41.2 ) Recorded as Regulatory Assets $ 161.4 $ 178.5 $ (10.2 ) $ 9.7 Deferred Income Taxes 2.9 5.2 (0.3 ) (0.1 ) Net of Tax AOCI 8.9 9.6 (0.8 ) (0.1 ) Income Tax Expense (a) 2.0 — (0.2 ) — APCo Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 182.5 $ 216.2 $ 48.0 $ 92.9 Prior Service Cost (Credit) — 0.2 (60.4 ) (70.5 ) Recorded as Regulatory Assets $ 179.9 $ 213.7 $ (11.1 ) $ 7.7 Deferred Income Taxes 0.5 1.0 (0.3 ) 5.1 Net of Tax AOCI 1.7 1.7 (0.8 ) 9.6 Income Tax Expense (a) 0.4 — (0.2 ) — I&M Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 94.9 $ 133.2 $ 42.0 $ 81.3 Prior Service Cost (Credit) — 0.2 (56.9 ) (66.3 ) Recorded as Regulatory Assets $ 91.8 $ 128.2 $ (14.0 ) $ 13.7 Deferred Income Taxes 0.7 1.8 (0.2 ) 0.5 Net of Tax AOCI 2.0 3.4 (0.6 ) 0.8 Income Tax Expense (a) 0.4 — (0.1 ) — OPCo Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 189.6 $ 215.4 $ 22.6 $ 58.2 Prior Service Cost (Credit) — 0.1 (41.6 ) (48.5 ) Recorded as Regulatory Assets $ 189.6 $ 215.5 $ (19.0 ) $ 9.7 PSO Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 78.8 $ 91.0 $ 19.8 $ 37.3 Prior Service Credit — — (25.9 ) (30.2 ) Recorded as Regulatory Assets $ 78.8 $ 91.0 $ (6.1 ) $ 7.1 SWEPCo Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 97.4 $ 103.8 $ 24.7 $ 45.4 Prior Service Cost (Credit) — 0.1 (31.4 ) (36.6 ) Recorded as Regulatory Assets $ 97.4 $ 103.9 $ (3.7 ) $ 5.7 Deferred Income Taxes — — (0.6 ) 1.1 Net of Tax AOCI — — (2.0 ) 2.0 Income Tax Expense (a) — — (0.4 ) — (a) Amounts relate to the re-measurement of Deferred Income Taxes as a result of Tax Reform. In accordance with the accounting guidance for “Income Taxes”, re-measurement of Deferred Income Taxes related to AOCI must flow through the statement of income. Components of the change in amounts included in AOCI, Income Tax Expense and Regulatory Assets by Registrant are as follows: AEP Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (132.8 ) $ 107.5 $ (267.8 ) $ 68.4 Amortization of Actuarial Loss (82.8 ) (83.8 ) (36.7 ) (31.4 ) Amortization of Prior Service Credit (Cost) (1.0 ) (2.3 ) 69.1 69.0 Change for the Year Ended December 31, $ (216.6 ) $ 21.4 $ (235.4 ) $ 106.0 AEP Texas Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (11.1 ) $ 7.1 $ (23.6 ) $ 6.4 Amortization of Actuarial Loss (7.0 ) (7.1 ) (3.2 ) (2.8 ) Amortization of Prior Service Credit (Cost) — (0.4 ) 5.8 6.0 Change for the Year Ended December 31, $ (18.1 ) $ (0.4 ) $ (21.0 ) $ 9.6 APCo Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (23.3 ) $ 6.2 $ (38.6 ) $ 11.4 Amortization of Actuarial Loss (10.4 ) (10.8 ) (6.3 ) (5.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.1 ) 10.1 10.1 Change for the Year Ended December 31, $ (33.9 ) $ (4.7 ) $ (34.8 ) $ 16.1 I&M Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (28.6 ) $ 13.2 $ (34.9 ) $ 7.9 Amortization of Actuarial Loss (9.7 ) (10.0 ) (4.4 ) (3.7 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.1 ) 9.4 9.4 Change for the Year Ended December 31, $ (38.5 ) $ 3.1 $ (29.9 ) $ 13.6 OPCo Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (18.0 ) $ 1.5 $ (31.3 ) $ 9.4 Amortization of Actuarial Loss (7.8 ) (8.1 ) (4.3 ) (3.8 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.1 ) 6.9 6.9 Change for the Year Ended December 31, $ (25.9 ) $ (6.7 ) $ (28.7 ) $ 12.5 PSO Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (7.9 ) $ 1.3 $ (15.5 ) $ 3.9 Amortization of Actuarial Loss (4.3 ) (4.4 ) (2.0 ) (1.8 ) Amortization of Prior Service Credit (Cost) — (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (12.2 ) $ (3.4 ) $ (13.2 ) $ 6.4 SWEPCo Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.5 ) $ 11.5 $ (18.4 ) $ 4.0 Amortization of Actuarial Loss (4.9 ) (4.8 ) (2.3 ) (1.9 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.3 ) 5.2 5.0 Change for the Year Ended December 31, $ (6.5 ) $ 6.4 $ (15.5 ) $ 7.1 Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. Pension and OPEB Assets The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan OPEB December 31, Company 2017 2016 2017 2016 AEP Texas 8.8 % 8.6 % 8.5 % 8.7 % APCo 12.6 % 12.6 % 15.8 % 16.0 % I&M 12.3 % 12.1 % 12.2 % 12.1 % OPCo 9.8 % 9.8 % 11.5 % 11.8 % PSO 5.6 % 5.5 % 5.5 % 5.6 % SWEPCo 6.0 % 6.0 % 6.4 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2017 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 318.6 $ — $ — $ — $ 318.6 6.2 % International 507.7 — — — 507.7 9.8 % Options — 26.9 — — 26.9 0.5 % Common Collective Trusts (c) — — — 452.9 452.9 8.7 % Subtotal – Equities 826.3 26.9 — 452.9 1,306.1 25.2 % Fixed Income: United States Government and Agency Securities — 1,376.5 — — 1,376.5 26.6 % Corporate Debt — 1,277.0 — — 1,277.0 24.7 % Foreign Debt — 296.9 — — 296.9 5.7 % State and Local Government — 31.7 — — 31.7 0.6 % Other – Asset Backed — 10.2 — — 10.2 0.2 % Subtotal – Fixed Income — 2,992.3 — — 2,992.3 57.8 % Infrastructure (c) — — — 59.5 59.5 1.2 % Real Estate (c) — — — 290.3 290.3 5.6 % Alternative Investments (c) — — — 446.0 446.0 8.6 % Securities Lending — 501.8 — — 501.8 9.7 % Securities Lending Collateral (a) — — — (503.5 ) (503.5 ) (9.7 )% Cash and Cash Equivalents (c) 0.4 35.6 — 21.2 57.2 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 24.4 24.4 0.5 % Total $ 826.7 $ 3,556.6 $ — $ 790.8 $ 5,174.1 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2017 $ 57.6 $ 254.9 $ 411.1 $ 723.6 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — — — — Relating to Assets Sold During the Period — — — — Purchases and Sales — — — — Transfers into Level 3 — — — — Transfers out of Level 3 (a) (57.6 ) (254.9 ) (411.1 ) (723.6 ) Balance as of December 31, 2017 $ — $ — $ — $ — (a) The classification of Level 3 assets from the prior year was corrected in the current year presentation and included within the fair value hierarchy table as of December 31, 2017 as “Other” investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). Management concluded that these disclosure errors were immaterial individually and in the aggregate to all prior periods presented. The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2017 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 307.1 $ — $ — $ — $ 307.1 17.7 % International 306.9 — — — 306.9 17.7 % Options — 9.4 — — 9.4 0.5 % Common Collective Trusts (b) — — — 153.6 153.6 8.9 % Subtotal – Equities 614.0 9.4 — 153.6 777.0 44.8 % Fixed Income: Common Collective Trust – Debt (b) — — — 185.0 185.0 10.7 % United States Government and Agency Securities — 187.4 — — 187.4 10.8 % Corporate Debt — 214.1 — — 214.1 12.4 % Foreign Debt — 40.7 — — 40.7 2.4 % State and Local Government 49.7 16.8 — — 66.5 3.8 % Other – Asset Backed — 0.2 — — 0.2 — % Subtotal – Fixed Income 49.7 459.2 — 185.0 693.9 40.1 % Trust Owned Life Insurance: International Equities — 105.4 — — 105.4 6.1 % United States Bonds — 118.2 — — 118.2 6.8 % Subtotal – Trust Owned Life Insurance — 223.6 — — 223.6 12.9 % Cash and Cash Equivalents (b) 36.7 — — 4.2 40.9 2.4 % Other – Pending Transactions and Accrued Income (a) — — — (2.9 ) (2.9 ) (0.2 )% Total $ 700.4 $ 692.2 $ — $ 339.9 $ 1,732.5 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 357.8 $ — $ — $ — $ 357.8 7.4 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share. Accumulated Benefit Obligation The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,951.3 $ 421.4 $ 648.0 $ 592.4 $ 483.4 $ 256.9 $ 289.4 Nonqualified Pension Plans 73.9 3.8 0.2 0.4 0.1 2.7 2.2 Total as of December 31, 2017 $ 5,025.2 $ 425.2 $ 648.2 $ 592.8 $ 483.5 $ 259.6 $ 291.6 Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 404.7 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 3.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 408.5 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 78.0 $ 4.0 $ 0.4 $ 1.0 $ 0.4 $ 2.7 $ 2.2 Accumulated Benefit Obligation $ 73.9 $ 3.8 $ 0.2 $ 0.4 $ 0.1 $ 2.7 $ 2.2 Fair Value of Plan Assets — — — — — — — Underfunded Accumulated Benefit Obligation as of December 31, 2017 $ (73.9 ) $ (3.8 ) $ (0.2 ) $ (0.4 ) $ (0.1 ) $ (2.7 ) $ (2.2 ) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 3.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 3.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 — 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (3.8 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2018 : Company Pension Plans OPEB (in millions) AEP $ 100.7 $ 4.2 AEP Texas 3.6 — APCo 9.6 2.5 I&M 1.6 — OPCo 1.2 — PSO 0.2 — SWEPCo 2.8 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 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 AEP Texas and OPCo. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. 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. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2017 , 2016 and 2015 and reportable segment balance sheet information as of December 31, 2017 and 2016 . Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2017 Revenues from: External Customers $ 9,095.1 $ 4,328.9 $ 178.4 $ 1,771.4 $ 51.1 $ — $ 15,424.9 Other Operating Segments 96.9 90.4 588.3 103.7 69.7 (949.0 ) — Total Revenues $ 9,192.0 $ 4,419.3 $ 766.7 $ 1,875.1 $ 120.8 $ (949.0 ) $ 15,424.9 Asset Impairments and Other Related Charges $ 33.6 $ — $ — $ 53.5 $ — $ — $ 87.1 Depreciation and Amortization 1,142.5 667.5 102.2 24.2 0.3 60.5 (b) 1,997.2 Interest and Investment Income 6.8 7.7 1.2 10.3 23.3 (33.3 ) 16.0 Carrying Costs Income 15.2 3.6 (0.2 ) — — — 18.6 Interest Expense 540.0 244.1 72.8 18.5 63.9 (44.3 ) (b) 895.0 Income Tax Expense (Credit) 425.6 127.2 189.8 189.7 37.4 — 969.7 Income (Loss) from Continuing Operations $ 803.3 $ 636.4 $ 355.6 $ 166.0 $ (32.4 ) $ — $ 1,928.9 Income (Loss) from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 803.3 $ 636.4 $ 355.6 $ 166.0 $ (32.4 ) $ — $ 1,928.9 Gross Property Additions $ 2,343.2 $ 1,558.4 $ 1,542.8 $ 328.5 $ 15.6 $ (90.4 ) $ 5,698.1 Total Property, Plant and Equipment $ 43,294.4 $ 16,371.2 $ 7,110.2 $ 644.6 $ 374.5 $ (366.4 ) (b) $ 67,428.5 Accumulated Depreciation and Amortization 13,153.4 3,768.3 176.6 75.0 180.6 (186.9 ) (b) 17,167.0 Total Property, Plant and Equipment – Net $ 30,141.0 $ 12,602.9 $ 6,933.6 $ 569.6 $ 193.9 $ (179.5 ) (b) $ 50,261.5 Total Assets $ 37,579.7 $ 16,060.7 $ 8,141.8 $ 2,009.8 $ 3,959.1 (c) $ (3,022.0 ) (b) (d) $ 64,729.1 Investments in Equity Method Investees $ 37.1 $ 1.5 $ 742.9 $ 16.6 $ 14.2 $ — $ 812.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,038.1 $ 663.1 $ 50.0 $ — $ 2.5 $ — $ 1,753.7 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,801.4 4,705.4 2,631.3 (0.3 ) 1,281.8 — 19,419.6 Total Long-term Debt $ 11,889.5 $ 5,368.5 $ 2,681.3 $ 31.9 $ 1,284.3 $ (82.2 ) $ 21,173.3 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (b) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (b) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 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 $ 3,883.4 (c) $ (2,417.3 ) (b) (d) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 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 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (b) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (b) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 3,628.5 (c) $ (2,959.3 ) (b) (d) $ 61,683.1 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Includes the elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (d) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable. Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo) The Registrant Subsidiaries 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 AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. 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 RTO’s 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 provide 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 makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transcos 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 years ended December 31, 2017 , 2016 and 2015 and reportable segment balance sheet information as of December 31, 2017 and 2016 . State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2017 (in millions) Revenues from: External Customers $ 141.9 $ — $ — $ 141.9 Sales to AEP Affiliates 580.5 — — 580.5 Other Revenues 0.8 — — 0.8 Total Revenues $ 723.2 $ — $ — $ 723.2 Depreciation and Amortization $ 97.1 $ — $ — $ 97.1 Interest Income 0.7 82.9 (82.4 ) (a) 1.2 Allowance for Equity Funds Used During Construction 52.3 — — 52.3 Interest Expense 68.0 82.4 (82.4 ) (a) 68.0 Income Tax Expense (Credit) 147.0 0.2 — 147.2 Net Income $ 285.8 $ 0.3 (b) $ — $ 286.1 Gross Property Additions $ 1,522.5 $ — $ — $ 1,522.5 Total Transmission Property $ 6,780.2 $ — $ — $ 6,780.2 Accumulated Depreciation and Amortization 170.4 — — 170.4 Total Transmission Property - Net $ 6,609.8 $ — $ — $ 6,609.8 Notes Receivable - Affiliated $ — $ 2,550.4 $ (2,550.4 ) (c) $ — Total Assets $ 7,072.9 $ 2,590.1 (d) $ (2,594.9 ) (e) $ 7,068.1 Total Long-Term Debt $ 2,575.0 $ 2,550.4 $ (2,575.0 ) (c) $ 2,550.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2016 (in millions) Revenues from: External Customers $ 110.4 $ — $ — $ 110.4 Sales to AEP Affiliates 367.5 — — 367.5 Other Revenues 0.1 — — 0.1 Total Revenues $ 478.0 $ — $ — $ 478.0 Depreciation and Amortization $ 65.9 $ — $ — $ 65.9 Interest Income 0.1 57.8 (57.5 ) (a) 0.4 Allowance for Equity Funds Used During Construction 52.3 — — 52.3 Interest Expense 45.6 57.9 (57.5 ) (a) 46.0 Income Tax Expense (Credit) 94.4 (0.3 ) — 94.1 Net Income (Loss) $ 193.3 $ (0.6 ) (b) $ — $ 192.7 Gross Property Additions $ 1,166.0 $ — $ — $ 1,166.0 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 $ 1,987.7 (d) $ (1,975.4 ) (e) $5,349.8 Total Long-Term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $1,932.0 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2015 (in millions) Revenues from: External Customers $ 84.3 $ — $ — $ 84.3 Sales to AEP Affiliates 225.6 — — 225.6 Other 0.3 — — 0.3 Total Revenues $ 310.2 $ — $ — $ 310.2 Depreciation and Amortization $ 42.4 $ — $ — $ 42.4 Interest Income 0.1 49.6 (49.6 ) (a) 0.1 Allowance for Equity Funds Used During Construction 53.0 — — 53.0 Interest Expense 34.4 49.8 (49.6 ) (a) 34.6 Income Tax Expense (Credit) 60.1 (0.1 ) — 60.0 Net Income (Loss) $ 133.2 $ (0.3 ) (b) $ — $ 132.9 Gross Property Additions $ 1,008.9 $ — $ — $ 1,008.9 Total Assets $ 4,143.6 $ 1,588.4 (d) $ (1,575.5 ) (e) $ 4,156.5 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes the elimination of AEPTCo Parent’s equity earnings in State Transcos. (c) Elimination of intercompany debt. (d) Includes the elimination of AEPTCo Parent’s investments in State Transcos. (e) Primarily relates to the elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging

Derivatives and Hedging	12 Months Ended
	Dec. 31, 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. AEPEP 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 December 31, 2017 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 358.7 — 57.4 38.5 10.4 10.3 22.7 Coal Tons 2.0 — — 2.0 — — — Natural Gas MMBtus 53.7 — 1.1 0.7 — — 18.3 Heating Oil and Gasoline Gallons 6.9 1.4 1.3 0.7 1.6 0.7 0.8 Interest Rate USD $ 50.7 $ — $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP AEP Texas 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 1.5 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. AEP netted cash collateral received from third parties against short-term and long-term risk management assets in the amounts of $9.4 million and $7.9 million for the years ended December 31, 2017 and 2016. AEP netted cash collateral paid to third parties against short-term and long-term risk management liabilities in the amounts of $9 million and $7.6 million for the years ended December 31, 2017 and 2016. The netted cash collateral from third parties against short-term and long-term risk management assets and netted cash collateral paid to third parties against short-term and long-term risk management liabilities were immaterial for the other Registrants for the years ended December 31, 2017 and 2016. The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 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 (a) (in millions) Current Risk Management Assets $ 389.0 $ 17.5 $ 2.5 $ 409.0 $ (282.8 ) $ 126.2 Long-term Risk Management Assets 300.9 6.3 — 307.2 (25.1 ) 282.1 Total Assets 689.9 23.8 2.5 716.2 (307.9 ) 408.3 Current Risk Management Liabilities 334.6 9.0 — 343.6 (282.0 ) 61.6 Long-term Risk Management Liabilities 280.6 58.3 8.6 347.5 (25.5 ) 322.0 Total Liabilities 615.2 67.3 8.6 691.1 (307.5 ) 383.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 74.7 $ (43.5 ) $ (6.1 ) $ 25.1 $ (0.4 ) $ 24.7 Fair Value of Derivative Instruments December 31, 2016 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 (a) (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 AEP Texas Fair Value of Derivative Instruments December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 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 $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.4 $ (0.2 ) $ 0.2 APCo Fair Value of Derivative Instruments December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 75.6 $ (50.7 ) $ 24.9 Long-term Risk Management Assets 2.4 (1.3 ) 1.1 Total Assets 78.0 (52.0 ) 26.0 Current Risk Management Liabilities 50.6 (49.3 ) 1.3 Long-term Risk Management Liabilities 1.4 (1.2 ) 0.2 Total Liabilities 52.0 (50.5 ) 1.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 26.0 $ (1.5 ) $ 24.5 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 $ 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 47.2 $ (39.6 ) $ 7.6 Long-term Risk Management Assets 1.6 (0.9 ) 0.7 Total Assets 48.8 (40.5 ) 8.3 Current Risk Management Liabilities 48.5 (45.0 ) 3.5 Long-term Risk Management Liabilities 0.9 (0.8 ) 0.1 Total Liabilities 49.4 (45.8 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.6 ) $ 5.3 $ 4.7 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 6.4 — 6.4 Long-term Risk Management Liabilities 126.0 — 126.0 Total Liabilities 132.4 — 132.4 Total MTM Derivative Contract Net Liabilities $ (131.8 ) $ — $ (131.8 ) 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 $ 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 6.6 $ (0.2 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 6.6 (0.2 ) 6.4 Current Risk Management Liabilities 0.2 (0.2 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.2 (0.2 ) — Total MTM Derivative Contract Net Assets $ 6.4 $ — $ 6.4 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 7.0 $ (0.6 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 7.0 (0.6 ) 6.4 Current Risk Management Liabilities 0.8 (0.6 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.8 (0.6 ) 0.2 Total MTM Derivative Contract Net Assets $ 6.2 $ — $ 6.2 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 Year Ended December 31, 2017 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.1 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 42.8 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.6 5.3 — — 0.1 Purchased Electricity for Resale 5.6 — 2.0 0.6 — — — Other Operation 0.8 0.1 0.1 0.1 0.1 0.1 0.1 Maintenance 0.7 0.2 0.1 0.1 0.1 0.1 0.1 Regulatory Assets (a) (29.4 ) — — (7.4 ) (22.0 ) — 0.3 Regulatory Liabilities (a) 109.4 0.1 40.4 15.9 — 24.8 24.3 Total Gain (Loss) on Risk Management Contracts $ 136.0 $ 0.4 $ 43.2 $ 14.6 $ (21.8 ) $ 25.0 $ 24.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — — Generation & Marketing Revenues 59.4 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 — 3.5 0.3 — — — Other Operation (1.6 ) (0.4 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance (1.8 ) (0.4 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.8 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 0.4 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 0.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — — Generation & Marketing Revenues 54.9 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 — 2.0 0.4 — — — Other Operation (3.3 ) (0.8 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance (3.3 ) (0.7 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 0.4 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 — 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ (1.1 ) $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 (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. For 2017, 2016, and 2015, hedging gains and losses were immaterial. For 2017 , 2016 and 2015 , 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 2017 , 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During 2017, 2016 and 2015, 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 2017 , 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2017 , 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related 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 into qualifying foreign currency hedging relationships. During the years ended December 31, 2017 and 2016, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2017 , 2016 and 2015 , 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 December 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 22.0 $ — $ 11.2 $ — Hedging Liabilities (a) 65.5 — 46.7 — AOCI Gain (Loss) Net of Tax (28.4 ) (13.0 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 5.5 (0.8 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 120 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassed to Reclassed to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) AEP Texas $ (4.5 ) $ (0.9 ) $ (5.4 ) $ (0.9 ) APCo 2.2 0.7 2.9 0.7 I&M (10.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 1.9 1.1 3.0 1.1 PSO 2.6 0.8 3.4 0.8 SWEPCo (6.0 ) (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 Investors Service Inc., S&P Global Inc. 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) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of December 31, 2017 and 2016. 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 table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount 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: AEP Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision December 31, Netting Arrangements Collateral Posted is Triggered (in millions) 2017 $ 243.6 $ 1.3 $ 223.1 2016 259.6 0.4 235.8 Amounts for APCo and I&M are immaterial for years ended December 31, 2017 and 2016.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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: December 31, 2017 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 21,173.3 $ 23,649.6 $ 20,391.2 (a) $ 22,211.9 (a) AEP Texas 3,649.3 3,964.8 3,217.7 3,463.2 AEPTCo 2,550.4 2,782.9 1,932.0 1,984.3 APCo 3,980.1 4,782.6 4,033.9 4,613.2 I&M 2,745.1 3,014.7 2,471.4 2,661.6 OPCo 1,719.3 2,064.3 1,763.9 2,092.5 PSO 1,286.5 1,457.1 1,286.0 1,419.0 SWEPCo 2,441.9 2,645.9 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 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include 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. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 220.1 $ — $ — $ 220.1 Fixed Income Securities – Mutual Funds (b) 104.3 — (1.4 ) 102.9 Equity Securities – Mutual Funds 17.0 19.7 — 36.7 Total Other Temporary Investments $ 341.4 $ 19.7 $ (1.4 ) $ 359.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (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: Years Ended December 31, 2017 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 14.2 2.3 10.7 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 years ended December 31, 2017 , 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2017 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 $ 17.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 981.2 29.7 (3.6 ) 785.4 27.1 (5.5 ) Corporate Debt 58.7 3.8 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 8.8 0.8 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,048.7 34.3 (5.0 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,461.7 868.2 (75.5 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,527.6 $ 902.5 $ (80.5 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2017 2016 2015 (in millions) Proceeds from Investment Sales $ 2,256.3 $ 2,957.7 $ 2,218.4 Purchases of Investments 2,300.5 3,000.0 2,272.0 Gross Realized Gains on Investment Sales 200.7 46.1 69.1 Gross Realized Losses on Investment Sales 146.0 24.4 53.0 The base cost of fixed income securities was $1 billion and $938 million as of December 31, 2017 and 2016 , respectively. The base cost of equity securities was $594 million and $592 million as of December 31, 2017 and 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 387.3 After 1 year through 5 years 287.4 After 5 years through 10 years 204.4 After 10 years 169.6 Total $ 1,048.7 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 183.2 $ — $ — $ 36.9 $ 220.1 Fixed Income Securities – Mutual Funds 102.9 — — — 102.9 Equity Securities – Mutual Funds (b) 36.7 — — — 36.7 Total Other Temporary Investments 322.8 — — 36.9 359.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 3.9 391.2 274.1 (285.4 ) 383.8 Cash Flow Hedges: Commodity Hedges (c) — 17.3 4.7 — 22.0 Fair Value Hedges — 2.5 — — 2.5 Total Risk Management Assets 3.9 411.0 278.8 (285.4 ) 408.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities – Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,795.9 $ 1,459.7 $ 278.8 $ (238.8 ) $ 3,295.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.1 $ 392.5 $ 196.9 $ (285.0 ) $ 309.5 Cash Flow Hedges: Commodity Hedges (c) — 23.9 41.6 — 65.5 Fair Value Hedges — 8.6 — — 8.6 Total Risk Management Liabilities $ 5.1 $ 425.0 $ 238.5 $ (285.0 ) $ 383.6 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 and Other Cash Deposits (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 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 155.2 $ — $ — $ — $ 155.2 Risk Management Assets Risk Management Commodity Contracts (c) — 0.5 — — 0.5 Total Assets $ 155.2 $ 0.5 $ — $ — $ 155.7 AEP Texas 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 $ 146.3 $ — $ — $ — $ 146.3 Risk Management Assets Risk Management Commodity Contracts (c) — 0.4 — (0.2 ) 0.2 Total Assets $ 146.3 $ 0.4 $ — $ (0.2 ) $ 146.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 16.3 $ — $ — $ — $ 16.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 52.5 25.1 (51.6 ) 26.0 Total Assets $ 16.3 $ 52.5 $ 25.1 $ (51.6 ) $ 42.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 51.2 $ 0.4 $ (50.1 ) $ 1.5 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 39.4 $ 9.1 $ (40.2 ) $ 8.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities – Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,469.2 $ 1,088.1 $ 9.1 $ (30.5 ) $ 2,535.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 47.6 $ 1.5 $ (45.5 ) $ 3.6 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ — $ — $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 132.4 $ — $ 132.4 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 6.4 $ (0.2 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.2 $ (0.2 ) $ — 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 6.7 $ (0.6 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.8 $ (0.6 ) $ 0.2 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 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 December 31, 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 periods 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. 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. There were no transfers between Level 1 and Level 2 during the years ended December 31, 2017 , 2016 and 2015 . 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: Year Ended December 31, 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) 37.3 17.2 4.0 (1.4 ) 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) 33.6 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (18.8 ) — — — — — Settlements (50.6 ) (18.9 ) (7.1 ) 7.4 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.2 — — — — — Transfers out of Level 3 (e) (10.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 30.2 25.0 7.9 (19.4 ) 6.2 6.0 Balance as of December 31, 2017 $ 40.3 $ 24.7 $ 7.6 $ (132.4 ) $ 6.2 $ 5.9 Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 (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 assets/liabilities or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 225.1 $ 233.7 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 263.00 $ 36.32 Counterparty Credit Risk (b) 8 456 180 Natural Gas Contracts — 0.2 Discounted Cash Flow Forward Market Price (c) 2.37 2.96 2.62 FTRs 53.7 4.6 Discounted Cash Flow Forward Market Price (a) (55.62 ) 54.88 0.41 Total $ 278.8 $ 238.5 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 December 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.4 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 24.3 — Discounted Cash Flow Forward Market Price (0.36 ) 7.15 1.62 Total $ 25.1 $ 0.4 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 December 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.5 $ 0.3 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 8.6 1.2 Discounted Cash Flow Forward Market Price (0.36 ) 5.75 0.86 Total $ 9.1 $ 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 December 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 132.4 Discounted Cash Flow Forward Market Price (a) $ 30.52 $ 170.43 $ 44.62 Counterparty Credit Risk (b) 8 190 136 Total $ — $ 132.4 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 December 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 6.4 $ 0.2 Discounted Cash Flow Forward Market Price $ (6.62 ) $ 1.41 $ (0.76 ) 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 December 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 0.2 Discounted Cash Flow Forward Market Price (c) $ 2.37 $ 2.96 $ 2.62 FTRs 6.7 0.6 Discounted Cash Flow Forward Market Price (a) (6.62 ) 1.41 (0.76 ) Total $ 6.7 $ 0.8 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of December 31, 2017 and 2016 : 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	12 Months Ended
	Dec. 31, 2017
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Federal Tax Reform In December 2017, legislation referred to as Tax Reform was signed into law. The majority of the provisions in the new legislation are effective for taxable years beginning after December 31, 2017. Tax Reform includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and also includes provisions specific to regulated public utilities. The more significant changes that affect the Registrants include the reduction in the corporate federal income tax rate from 35% to 21%, and several technical provisions including, among others, limiting the utilization of net operating losses arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward period. The Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonus depreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits. Provisional Amounts Given the significance of the legislative changes resulting from Tax Reform, the timing of its enactment, and the widespread applicability to registrants, the SEC staff recognized the potential challenges faced by registrants when reflecting the effects of Tax Reform in their 2017 financial statements. Accordingly, in order to address potential uncertainty or diversity of views in practice regarding the application of the accounting guidance for “Income Taxes” in situations where a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for “Income Taxes” for certain tax effects of Tax Reform for the reporting period in which the legislation was enacted, the SEC staff issued Staff Accounting Bulletin 118 (SAB 118) in December 2017. For such areas of analysis that are incomplete, SAB 118 provides for up to a one year period in which to complete the required analyses and accounting required by the accounting guidance for “Income Taxes,” referred to as the measurement period. SAB 118 describes three categories associated with a registrant’s status of accounting for Tax Reform during the measurement period: (a) a registrant is complete with its accounting for certain effects of Tax Reform, (b) a registrant’s accounting is incomplete but is able to determine a reasonable estimate for certain effects of Tax Reform and records that estimate as a provisional amount, or (c) the accounting is incomplete and a registrant is not able to determine a reasonable estimate and therefore continues to apply existing accounting guidance for income taxes, based on the provisions of the tax laws that were in effect immediately prior to the enactment of the Tax Reform legislation. For items in which the accounting assessment is complete or a reasonable estimate can be made, a registrant must reflect the income tax effects of Tax Reform for those items in its financial statements that include the enactment of the Tax Reform legislation. SAB 118 also requires certain disclosures to provide information about the material financial reporting impacts, if any, due to Tax Reform for which the accounting is not complete. Subsequent disclosures in future reporting periods in which the accounting is completed are also a requirement of the guidance. The Registrants have made a reasonable estimate for the measurement and accounting of the effects of Tax Reform which have been reflected in the December 31, 2017 financial statements as provisional amounts based on information available. While the Registrants were able to make reasonable estimates of the impact of Tax Reform, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative temporary differences or as a result of additional guidance or technical corrections that may be issued by the IRS that may impact management’s interpretation and assumptions utilized. The Registrants expect to complete the analysis of the provisional items during the second half of 2018. The recorded provisional amounts include $154 million of excess accumulated deferred income taxes (Excess ADIT) related to AEP Transmission Holdco’s equity investment in ETT. ETT is a three-member limited liability company that is a partnership for federal income tax purposes. The rates ETT is permitted to charge its customers are regulated by the PUCT. Those rates contemplate deferred taxes; however, the income tax effects of ETT’s activities are the responsibility of its members, including AEP Transmission Holdco. As a result, AEP’s proportionate share of the Excess ADIT related to ETT is reflected by AEP Transmission Holdco and is reflected in AEP’s December 31, 2017 balance sheet as a reduction in Deferred Income Taxes with a corresponding increase in Regulatory Liabilities and Deferred Investment Tax Credits. AEP’s accounting for Excess ADIT related to partnerships is provisional as it may be subject to further interpretation of Tax Reform. Impact of Tax Reform on the Financial Statements Changes in the Code due to Tax Reform had a material impact on the Registrants’ 2017 financial statements. In accordance with the accounting guidance for “Income Taxes”, the effect of a change in tax law must be recognized at the date of enactment. The accounting guidance for “Income Taxes” also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences will be realized or settled. As a result, the Registrants’ deferred tax assets and liabilities were re-measured using the newly enacted tax rate of 21% in December 2017. This re-measurement resulted in a significant reduction in the Registrants’ net accumulated deferred income tax liability. With respect to the Registrants’ regulated operations, the reduction of the net accumulated deferred income tax liability was primarily offset by a corresponding decrease in income tax related regulatory assets and an increase in income tax related regulatory liabilities because the benefit of the lower federal tax rate is expected to be provided to customers. However, when the underlying asset or liability giving rise to the temporary difference was not previously contemplated in regulated rates, the re-measurement of the deferred taxes on those assets or liabilities was recorded as an adjustment to income tax expense. For the Registrants’ unregulated operations, the re-measurement of deferred taxes arising from those operations was recorded as an adjustment to income tax expense. The following tables provide a summary of the impact of Tax Reform on the Registrants’ 2017 financial statements. Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Decrease in Deferred Income Tax Liabilities $ 6,101.1 $ 807.1 $ 558.6 $ 1,296.4 $ 808.7 $ 743.1 $ 538.6 $ 782.9 This decrease in deferred income tax liabilities resulted in an increase in income tax related regulatory liabilities, a decrease in income tax related regulatory assets and an adjustment to income tax expense as shown in the table below. Year Ended December 31, 2017 AEP (c) AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Increase (Decrease) in Income Tax Expense (a) $ (16.5 ) $ (117.4 ) (b) $ 0.6 $ 5.7 $ 2.3 $ (14.3 ) (b) $ 2.8 $ 0.7 Decrease in Regulatory Assets 470.2 12.1 66.9 129.1 85.3 62.7 8.3 69.8 Increase in Regulatory Liabilities 5,614.4 677.6 492.3 1,173.0 725.7 666.1 533.1 713.8 (a) In 2017, in contemplation of corporate federal tax reform, the Registrants adopted a method under Internal Revenue Section 162 for deducting repair and maintenance costs associated with transmission and distribution property. This change resulted in a decrease in state income tax expense of approximately $10 million that has been excluded from the tables above. (b) AEP Texas and OPCo recorded favorable adjustments to income tax expense of approximately $113 million and $16 million related to previously owned deregulated generation assets and certain deferred fuel amounts, respectively. (c) The effect of Tax Reform on AEP’s other business operations (other than the Registrant Subsidiaries), which primarily include unregulated activities in the Generation & Marketing segment, transmission operations reflected in the AEP Transmission Holdco segment and activities recorded in Corporate and Other, increased income tax expense for the year-ended December 31, 2017 by approximately $103 million . Regulatory Treatment As a result of Tax Reform, the Registrants recognized a regulatory liability for approximately $4.4 billion of Excess ADIT, as well as an incremental liability of $1.2 billion to reflect the $4.4 billion Excess ADIT on a pre-tax basis, which is presented in Regulatory Liabilities and Deferred Income Taxes on the balance sheets. The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. Approximately $3.2 billion of the Excess ADIT relates to temporary differences associated with depreciable property. The Tax Reform legislation includes certain rate normalization requirements that stipulate how the portion of the total Excess ADIT that is related to certain depreciable property must be returned to customers. Specifically, for AEP’s regulated public utilities that are subject to those rate normalization requirements, Excess ADIT resulting from the reduction of the corporate tax rate with respect to prior depreciation or recovery deductions on property will be normalized using the average rate assumption method. As a result, once the amortization of this Excess ADIT is reflected in rates, customers will receive the benefits over the remaining weighted average useful life of the applicable property. For the remaining $1.2 billion of Excess ADIT, the Registrants expect to continue working with each state regulatory commission to determine the appropriate mechanism and time period over which to provide the benefits of Tax Reform to customers. The Registrants expect the mechanism and time period to provide the benefits of Tax Reform to customers will vary by jurisdiction and will reduce future cash flows, may impact financial condition, but is not expected to have a material impact on future net income. State Regulatory Matters Various state utility commissions have recently issued orders requiring public utilities, including the Registrants, to record regulatory liabilities to reflect the corporate federal income taxes currently collected in utility rates in excess of the enacted corporate federal income tax rate of 21% beginning January 1, 2018. See Note 4 - Rate Matters for additional information regarding state utility commission orders received impacting the Registrant Subsidiaries. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (4.0 ) $ (85.7 ) $ (127.5 ) $ 15.3 $ (106.5 ) $ 11.2 $ (77.1 ) $ (30.1 ) Deferred 856.6 63.3 256.0 166.9 202.1 141.3 122.7 84.8 Deferred Investment Tax Credits 48.6 (1.6 ) — (0.1 ) (4.7 ) — (1.6 ) (1.4 ) Total Federal 901.2 (24.0 ) 128.5 182.1 90.9 152.5 44.0 53.3 State and Local: Current 16.0 0.6 1.9 (1.4 ) (8.1 ) 0.2 (0.2 ) (0.9 ) Deferred 44.9 — 16.8 4.6 (1.4 ) 6.6 2.0 (4.3 ) Deferred Investment Tax Credits 7.6 — — — — — 4.3 — Total State and Local 68.5 0.6 18.7 3.2 (9.5 ) 6.8 6.1 (5.2 ) Income Tax Expense (Credit) Before Discontinued Operations $ 969.7 $ (23.4 ) $ 147.2 $ 185.3 $ 81.4 $ 159.3 $ 50.1 $ 48.1 Year Ended December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 40.9 $ (129.4 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 29.9 205.9 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (1.7 ) — (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 69.1 76.5 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) (8.8 ) 0.4 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) (0.4 ) 17.2 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — — — 3.2 — Total State and Local (31.8 ) (9.2 ) 17.6 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 59.9 $ 94.1 $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 Year Ended December 31, 2015 AEP AEP Texas AEPTCo (in millions) Federal: Current $ 107.3 $ 61.4 $ (126.3 ) Deferred 774.8 (7.1 ) 171.3 Deferred Investment Tax Credits — (1.7 ) — Total Federal 882.1 52.6 45.0 State and Local: Current 14.5 5.6 3.1 Deferred 23.0 — 11.9 Total State and Local 37.5 5.6 15.0 Income Tax Expense Before Discontinued Operations $ 919.6 $ 58.2 $ 60.0 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 1,928.9 $ 618.0 $ 2,052.3 Discontinued Operations (Net of Income Tax of $0, $0 and $6.2 in 2017, 2016 and 2015, Respectively) — 2.5 (283.7 ) Income Tax Expense (Credit) Before Discontinued Operations 969.7 (73.7 ) 919.6 Pretax Income $ 2,898.6 $ 546.8 $ 2,688.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 1,014.5 $ 191.4 $ 940.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 60.2 41.7 53.6 Investment Tax Credit Amortization (18.8 ) (12.3 ) (11.6 ) State and Local Income Taxes, Net 54.7 (20.7 ) 24.4 Removal Costs (32.7 ) (39.8 ) (28.8 ) AFUDC (37.4 ) (44.8 ) (51.6 ) Valuation Allowance (1.8 ) (128.3 ) 17.2 U.K. Windfall Tax — (12.9 ) — Tax Reform Adjustments (26.7 ) — — Tax Adjustments (35.8 ) (43.9 ) (20.1 ) Other (6.5 ) (4.1 ) (4.4 ) Income Tax Expense (Credit) Before Discontinued Operations $ 969.7 $ (73.7 ) $ 919.6 Effective Income Tax Rate 33.5 % (13.5 ) % 34.2 % AEP Texas Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 310.5 $ 146.6 $ 120.3 Discontinued Operations (Net of Income Tax of $0, $27.6 and $1.8 in 2017, 2016 and 2015, Respectively) — 48.8 1.4 Income Tax Expense (23.4 ) 59.9 58.2 Pretax Income $ 287.1 $ 255.3 $ 179.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 100.5 $ 89.4 $ 63.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.7 0.5 0.5 Investment Tax Credit Amortization (1.6 ) (1.7 ) (1.7 ) State and Local Income Taxes, Net 0.4 (6.0 ) 3.6 Parent Company Loss Benefit — (2.5 ) (3.1 ) Tax Reform Adjustments (117.4 ) — — Tax Adjustments (4.2 ) (4.9 ) (1.6 ) U.K. Windfall Tax — (12.9 ) — Other (1.8 ) (2.0 ) (2.5 ) Income Tax Expense (Credit) Before Discontinued Operations $ (23.4 ) $ 59.9 $ 58.2 Effective Income Tax Rate (8.2 ) % 23.5 % 32.4 % AEPTCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 286.1 $ 192.7 $ 132.9 Income Tax Expense 147.2 94.1 60.0 Pretax Income $ 433.3 $ 286.8 $ 192.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 151.7 $ 100.4 $ 67.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: AFUDC (18.3 ) (18.3 ) (18.6 ) State and Local Income Taxes, Net 12.2 11.4 9.8 Tax Reform Adjustments 0.6 — — Other 1.0 0.6 1.3 Income Tax Expense $ 147.2 $ 94.1 $ 60.0 Effective Income Tax Rate 34.0 % 32.8 % 31.1 % APCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 331.3 $ 369.1 $ 340.6 Income Tax Expense 185.3 199.1 194.3 Pretax Income $ 516.6 $ 568.2 $ 534.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 180.8 $ 198.9 $ 187.2 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 18.0 19.3 19.8 Investment Tax Credit Amortization (0.1 ) (0.1 ) (0.3 ) State and Local Income Taxes, Net 3.5 6.0 7.2 Removal Costs (12.4 ) (12.0 ) (9.9 ) AFUDC (5.0 ) (6.1 ) (7.0 ) Valuation Allowance — (1.7 ) 1.7 Tax Reform Adjustments 4.3 — — Other (3.8 ) (5.2 ) (4.4 ) Income Tax Expense $ 185.3 $ 199.1 $ 194.3 Effective Income Tax Rate 35.9 % 35.0 % 36.3 % I&M Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 186.7 $ 239.9 $ 204.8 Income Tax Expense 81.4 67.5 96.1 Pretax Income $ 268.1 $ 307.4 $ 300.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 93.8 $ 107.6 $ 105.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 11.4 6.7 9.5 Investment Tax Credit Amortization (4.7 ) (4.7 ) (3.3 ) State and Local Income Taxes, Net (1.0 ) 2.4 5.8 Removal Costs (13.3 ) (21.3 ) (12.6 ) AFUDC (5.6 ) (7.3 ) (6.2 ) Tax Adjustments 2.7 (14.2 ) (4.2 ) Tax Reform Adjustments (2.9 ) — — Other 1.0 (1.7 ) 1.8 Income Tax Expense $ 81.4 $ 67.5 $ 96.1 Effective Income Tax Rate 30.4 % 22.0 % 31.9 % OPCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 323.9 $ 282.2 $ 232.7 Income Tax Expense 159.3 143.8 126.5 Pretax Income $ 483.2 $ 426.0 $ 359.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 169.1 $ 149.1 $ 125.7 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.6 7.1 8.2 Investment Tax Credit Amortization — — (0.1 ) State and Local Income Taxes, Net 4.4 3.8 0.7 Tax Reform Adjustments (14.4 ) — — Other (7.4 ) (16.2 ) (8.0 ) Income Tax Expense $ 159.3 $ 143.8 $ 126.5 Effective Income Tax Rate 33.0 % 33.8 % 35.2 % PSO Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 72.0 $ 100.0 $ 92.5 Income Tax Expense 50.1 54.4 51.3 Pretax Income $ 122.1 $ 154.4 $ 143.8 Income Taxes on Pretax Income at Statutory Rate (35%) $ 42.7 $ 54.0 $ 50.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.3 0.8 0.5 Investment Tax Credit Amortization (1.6 ) (1.4 ) (1.8 ) State and Local Income Taxes, Net 4.0 4.2 5.1 AFUDC (0.2 ) (2.2 ) (3.1 ) Tax Reform Adjustments 2.8 — — Other 2.1 (1.0 ) 0.3 Income Tax Expense $ 50.1 $ 54.4 $ 51.3 Effective Income Tax Rate 41.0 % 35.2 % 35.7 % SWEPCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 137.5 $ 169.7 $ 196.0 Income Tax Expense 48.1 52.1 84.8 Pretax Income $ 185.6 $ 221.8 $ 280.8 Income Taxes on Pretax Income at Statutory Rate (35%) $ 65.0 $ 77.6 $ 98.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 1.9 3.2 3.1 Depletion (5.7 ) (5.5 ) (5.5 ) Investment Tax Credit Amortization (1.4 ) (1.2 ) (1.4 ) State and Local Income Taxes, Net (2.3 ) (14.7 ) 4.8 AFUDC (0.9 ) (3.9 ) (9.2 ) Tax Adjustments (9.9 ) (0.9 ) (3.9 ) Tax Reform Adjustments (0.4 ) — — Other 1.8 (2.5 ) (1.4 ) Income Tax Expense $ 48.1 $ 52.1 $ 84.8 Effective Income Tax Rate 25.9 % 23.5 % 30.2 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2017 2016 (in millions) Deferred Tax Assets $ 3,504.6 $ 2,753.0 Deferred Tax Liabilities (10,318.5 ) (14,637.4 ) Net Deferred Tax Liabilities $ (6,813.9 ) $ (11,884.4 ) Property Related Temporary Differences $ (5,680.6 ) $ (8,758.1 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 1,064.8 (292.2 ) Deferred State Income Taxes (1,124.4 ) (976.6 ) Securitized Assets (257.7 ) (535.6 ) Regulatory Assets (500.3 ) (896.9 ) Deferred Income Taxes on Other Comprehensive Loss 25.7 88.7 Accrued Nuclear Decommissioning (457.0 ) (666.8 ) Net Operating Loss Carryforward 86.6 101.2 Tax Credit Carryforward 174.7 45.1 Investment in Partnership (222.0 ) (349.6 ) Valuation Allowance — (1.8 ) All Other, Net 76.3 358.2 Net Deferred Tax Liabilities $ (6,813.9 ) $ (11,884.4 ) AEP Texas December 31, 2017 2016 (in millions) Deferred Tax Assets $ 221.0 $ 135.8 Deferred Tax Liabilities (1,134.1 ) (1,667.5 ) Net Deferred Tax Liabilities $ (913.1 ) $ (1,531.7 ) Property Related Temporary Differences $ (791.5 ) $ (1,056.1 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 140.9 (5.7 ) Deferred State Income Taxes (27.5 ) (24.2 ) Regulatory Assets (36.4 ) (61.3 ) Securitized Transition Assets (190.5 ) (407.0 ) Deferred Income Taxes on Other Comprehensive Loss 4.1 8.0 Deferred Revenues 10.9 18.0 All Other, Net (23.1 ) (3.4 ) Net Deferred Tax Liabilities $ (913.1 ) $ (1,531.7 ) AEPTCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 162.7 $ 61.4 Deferred Tax Liabilities (764.4 ) (923.5 ) Net Deferred Tax Liabilities $ (601.7 ) $ (862.1 ) Property Related Temporary Differences $ (654.7 ) $ (825.6 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 89.7 (37.2 ) Deferred State Income Taxes (77.4 ) (55.6 ) Deferred Federal Income Taxes on Deferred State Income Taxes 16.3 19.5 Net Operating Loss Carryforward 16.8 33.3 Valuation Allowance — 0.1 Tax Credit Carryforward 0.3 — All Other, Net 7.3 3.4 Net Deferred Tax Liabilities $ (601.7 ) $ (862.1 ) APCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 614.4 $ 413.5 Deferred Tax Liabilities (2,180.1 ) (3,085.8 ) Net Deferred Tax Liabilities $ (1,565.7 ) $ (2,672.3 ) Property Related Temporary Differences $ (1,308.2 ) $ (2,031.9 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 228.0 (73.1 ) Deferred State Income Taxes (335.7 ) (319.3 ) Regulatory Assets (83.9 ) (159.9 ) Securitized Assets (59.3 ) (106.9 ) Deferred Income Taxes on Other Comprehensive Loss (0.4 ) 4.5 Tax Credit Carryforward 16.6 11.7 All Other, Net (22.8 ) 2.6 Net Deferred Tax Liabilities $ (1,565.7 ) $ (2,672.3 ) I&M December 31, 2017 2016 (in millions) Deferred Tax Assets $ 1,096.4 $ 912.9 Deferred Tax Liabilities (2,050.2 ) (2,440.3 ) Net Deferred Tax Liabilities $ (953.8 ) $ (1,527.4 ) Property Related Temporary Differences $ (403.0 ) $ (579.4 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 137.6 (50.4 ) Deferred State Income Taxes (180.6 ) (158.7 ) Deferred Income Taxes on Other Comprehensive Loss 3.9 8.8 Accrued Nuclear Decommissioning (457.0 ) (666.8 ) Regulatory Assets (43.8 ) (81.0 ) Net Operating Loss Carryforward 1.6 7.1 All Other, Net (12.5 ) (7.0 ) Net Deferred Tax Liabilities $ (953.8 ) $ (1,527.4 ) OPCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 286.0 $ 232.4 Deferred Tax Liabilities (1,048.9 ) (1,578.5 ) Net Deferred Tax Liabilities $ (762.9 ) $ (1,346.1 ) Property Related Temporary Differences $ (761.2 ) $ (1,090.8 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 127.3 (43.6 ) Deferred State Income Taxes (41.7 ) (34.6 ) Regulatory Assets (107.7 ) (174.1 ) Deferred Income Taxes on Other Comprehensive Loss (0.6 ) (1.6 ) Deferred Fuel and Purchased Power (24.5 ) (117.6 ) All Other, Net 45.5 116.2 Net Deferred Tax Liabilities $ (762.9 ) $ (1,346.1 ) PSO December 31, 2017 2016 (in millions) Deferred Tax Assets $ 269.2 $ 153.8 Deferred Tax Liabilities (911.2 ) (1,212.6 ) Net Deferred Tax Liabilities $ (642.0 ) $ (1,058.8 ) Property Related Temporary Differences $ (623.8 ) $ (927.3 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 111.6 (3.2 ) Deferred State Income Taxes (142.7 ) (128.5 ) Regulatory Assets (34.4 ) (67.6 ) Deferred Income Taxes on Other Comprehensive Loss (0.8 ) (1.8 ) Deferred Federal Income Taxes on Deferred State Income Taxes 33.5 50.6 Net Operating Loss Carryforward 23.1 16.5 Tax Credit Carryforward 0.7 — All Other, Net (9.2 ) 2.5 Net Deferred Tax Liabilities $ (642.0 ) $ (1,058.8 ) SWEPCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 349.4 $ 230.5 Deferred Tax Liabilities (1,267.1 ) (1,837.4 ) Net Deferred Tax Liabilities $ (917.7 ) $ (1,606.9 ) Property Related Temporary Differences $ (908.8 ) $ (1,445.2 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 135.8 (48.2 ) Deferred State Income Taxes (189.2 ) (175.1 ) Regulatory Assets (30.8 ) (40.7 ) Deferred Income Taxes on Other Comprehensive Loss 1.3 5.1 Capital/Impairment Loss - Turk Plant 17.4 20.3 Net Operating Loss Carryforward 38.7 40.3 Tax Credit Carryforward 0.8 0.1 All Other, Net 17.1 36.5 Net Deferred Tax Liabilities $ (917.7 ) $ (1,606.9 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015, AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. During 2017, the valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward was reversed, as the Company expects to have sufficient capital gains in the future to use this capital loss when realized. As of December 31, 2017, AEP and AEPTCo have recorded valuation allowances of $5 million and $2 million , respectively, against certain state and municipal net income tax operating loss carryforwards since future taxable income is not expected to be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires. 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 through 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. To resolve the issue under consideration, AEP and subsidiaries and the IRS exam team agreed to go to Appeals using Fast Track in December 2017. The issue is still waiting for resolution with Appeals. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the 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 and local jurisdictions. These taxing authorities routinely examine their 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 or local income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2017, Registrants specified in the table below recognized federal net income tax operating losses. The 2017 federal net income tax operating losses were driven primarily by bonus depreciation and deductions related to repair and maintenance costs associated with transmission and distribution property. Year Ended December 31, Company 2017 (in millions) AEP $ 230.1 AEP Texas 261.8 AEPTCo 344.1 I&M 332.6 PSO 213.9 SWEPCo 87.6 Substantially all of the 2017 federal net income tax operating losses will be carried back to 2015. As of December 31, 2017, AEP had $4 million of remaining unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, AEPTCo, I&M, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2017 as indicated in the table below: State Net Income Tax Operating Loss Year of Company State/Municipality Carryforward Expiration (in millions) AEP Arkansas $ 72.0 2022 AEP Kentucky 157.6 2037 AEP Louisiana 543.1 2037 AEP Oklahoma 799.8 2037 AEP Tennessee 27.9 2032 AEP Virginia 17.8 2037 AEP West Virginia 29.2 2037 AEP Ohio Municipal 106.3 2022 AEPTCo Oklahoma 296.9 2037 AEPTCo Ohio Municipal 64.2 2022 I&M West Virginia 14.1 2037 PSO Oklahoma 477.0 2037 SWEPCo Arkansas 71.2 2022 SWEPCo Louisiana 533.4 2037 As of December 31, 2017, AEP and AEPTCo have recorded valuation allowances of $5 million and $2 million , respectively, against certain state and municipal net income tax operating loss carryforwards since future taxable income is not expected to be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires for each state. As of December 31, 2017 and

Leases

Leases	12 Months Ended
	Dec. 31, 2017
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 14 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 231.3 $ 10.5 $ 1.7 $ 17.5 $ 88.4 $ 8.2 $ 4.4 $ 5.3 Amortization of Capital Leases 66.3 4.0 — 6.9 11.1 4.1 4.0 11.2 Interest on Capital Leases 16.7 0.8 — 3.7 3.2 0.5 0.6 3.6 Total Lease Rental Costs $ 314.3 $ 15.3 $ 1.7 $ 28.1 $ 102.7 $ 12.8 $ 9.0 $ 20.1 Year Ended December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 9.8 (a) $ 0.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 3.4 — 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 0.6 — 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 13.8 $ 0.9 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 8.1 (a) $ 0.5 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 2.9 — 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.4 — 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (b) $ 11.4 $ 0.5 $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 (a) Amounts include lease expenses related to AEP Texas Wind Farms that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for each of the years ended December 31, 2016 and 2015, respectively. See Note 7 for additional information. (b) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statement of income in the amount of $89 million for the year ended December 31, 2015. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 141.7 $ — $ — $ 42.5 $ 27.2 $ — $ 8.9 $ 33.4 Other Property, Plant and Equipment 373.3 32.7 0.2 18.0 34.0 22.8 18.0 122.4 Total Property, Plant and Equipment 515.0 32.7 0.2 60.5 61.2 22.8 26.9 155.8 Accumulated Amortization 229.0 10.0 — 19.0 21.1 10.6 15.3 94.0 Net Property, Plant and Equipment Under Capital Leases $ 286.0 $ 22.7 $ 0.2 $ 41.5 $ 40.1 $ 12.2 $ 11.6 $ 61.8 Obligations Under Capital Leases: Noncurrent Liability $ 238.8 $ 18.5 $ 0.1 $ 34.9 $ 34.3 $ 7.9 $ 8.3 $ 57.8 Liability Due Within One Year 59.0 4.2 0.1 6.6 5.8 4.3 3.5 11.2 Total Obligations Under Capital Leases $ 297.8 $ 22.7 $ 0.2 $ 41.5 $ 40.1 $ 12.2 $ 11.8 $ 69.0 December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ — $ — $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 26.1 — 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 26.1 — 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 7.7 — 18.1 25.4 11.6 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 18.4 $ — $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 14.8 $ — $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 3.6 — 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 18.4 $ — $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Future minimum lease payments consisted of the following as of December 31, 2017 : Capital Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 76.6 $ 5.1 $ 0.1 $ 10.0 $ 11.0 $ 4.7 $ 3.8 $ 14.3 2019 60.4 4.0 0.1 7.9 7.2 2.4 2.5 12.7 2020 49.7 3.4 — 7.0 6.4 1.8 1.7 10.9 2021 42.6 3.1 — 6.8 5.9 1.6 1.3 10.0 2022 35.1 2.6 — 6.4 5.4 1.1 1.0 8.9 Later Years 106.2 8.3 — 18.8 25.2 2.0 2.6 25.6 Total Future Minimum Lease Payments 370.6 26.5 0.2 56.9 61.1 13.6 12.9 82.4 Less Estimated Interest Element 72.8 3.8 — 15.4 21.0 1.4 1.3 13.4 Estimated Present Value of Future Minimum Lease Payments $ 297.8 $ 22.7 $ 0.2 $ 41.5 $ 40.1 $ 12.2 $ 11.6 $ 69.0 Noncancelable Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 245.9 $ 11.6 $ 1.7 $ 17.3 $ 91.3 $ 11.3 $ 4.8 $ 6.0 2019 237.9 10.7 1.3 15.6 90.3 10.3 4.3 5.7 2020 227.6 9.8 1.0 14.4 86.9 8.7 3.8 5.3 2021 210.7 8.9 0.4 12.0 82.4 6.3 2.9 4.9 2022 201.1 7.9 — 10.9 81.4 5.4 2.5 4.3 Later Years 137.1 21.5 — 23.3 16.3 19.5 6.5 9.5 Total Future Minimum Lease Payments $ 1,260.3 $ 70.4 $ 4.4 $ 93.5 $ 448.6 $ 61.5 $ 24.8 $ 35.7 Master Lease Agreements (Applies to all Registrants except AEPTCo) 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 December 31, 2017 , the maximum potential loss by the 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 $ 43.2 AEP Texas 10.0 APCo 8.8 I&M 3.3 OPCo 6.4 PSO 3.6 SWEPCo 3.7 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2017 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2018 $ 147.8 $ 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 2022 147.2 73.6 Total Future Minimum Lease Payments $ 738.4 $ 369.2 (a) AEP’s future minimum lease payments include equal shares from AEGCo and I&M. 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 assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $7 million and $8 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2017 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 December 31, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 December 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $50 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. As of December 31, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future minimum lease payments for the sales-and-leaseback transaction as of December 31, 2017 are $2 million based on estimated fuel burn and will be paid in 2018. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

Financing Activities

Financing Activities	12 Months Ended
	Dec. 31, 2017
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Issued 162,124 — Treasury Stock Reissued — (131,546 ) (a) Balance, December 31, 2017 512,210,644 20,205,046 (a) Reissued Treasury Stock used to fulfill share commitments related to AEP’s Share-based Compensation. See “Shared-based Compensation Plans” section of Note 15 for additional information. Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate Ranges as of Outstanding as of Interest Rate as of December 31, December 31, Company Maturity December 31, 2017 2017 2016 2017 2016 AEP (in millions) Senior Unsecured Notes 2017-2047 4.62% 2.15%-8.13% 1.65%-8.13% $ 16,478.3 $ 14,761.0 (f) Pollution Control Bonds (a) 2017-2042 (b) 3.06% 1.54%-6.30% 0.69%-6.30% 1,621.7 1,725.1 Notes Payable – Nonaffiliated (c) 2017-2032 3.00% 2.03%-6.37% 1.456%-6.37% 260.8 326.9 Securitization Bonds 2017-2028 (d) 3.70% 1.98%-5.31% 0.88%-5.31% 1,416.5 1,705.0 Spent Nuclear Fuel Obligation (e) 268.6 266.3 Other Long-term Debt 2017-2059 2.75% 1.15%-13.718% 1.15%-13.718% 1,127.4 1,606.9 Total Long-term Debt Outstanding $ 21,173.3 $ 20,391.2 (f) AEP Texas Senior Unsecured Notes 2018-2047 4.12% 2.40%-6.76% 2.61%-6.76% $ 1,932.2 $ 1,241.3 Pollution Control Bonds (a) 2017-2030 4.39% 1.75%-6.30% 4.00%-6.30% 490.5 530.3 Securitization Bonds 2017-2024 (d) 4.05% 1.98%-5.31% 0.88%-5.31% 1,026.1 1,245.8 Other Long-term Debt 2019-2059 2.76% 2.75%-4.50% 2.438%-4.50% 200.5 200.3 Total Long-term Debt Outstanding $ 3,649.3 $ 3,217.7 AEPTCo Senior Unsecured Notes 2018-2047 3.85% 2.68%-5.52% 2.68%-5.52% $ 2,550.4 $ 1,932.0 Total Long-term Debt Outstanding $ 2,550.4 $ 1,932.0 APCo Senior Unsecured Notes 2017-2045 5.20% 3.30%-7.00% 3.40%-7.00% $ 3,045.1 $ 2,972.4 Pollution Control Bonds (a) 2018-2042 (b) 2.44% 1.625%-5.38% 0.69%-5.38% 512.2 615.8 Securitization Bonds 2023-2028 (d) 2.98% 2.008%-3.772% 2.008%-3.772% 295.9 318.9 Other Long-term Debt 2019-2026 2.92% 2.73%-13.718% 2.06%-13.718% 126.9 126.8 Total Long-term Debt Outstanding $ 3,980.1 $ 4,033.9 I&M Senior Unsecured Notes 2019-2047 5.20% 3.20%-7.00% 3.20%-7.00% $ 1,809.0 $ 1,512.8 Pollution Control Bonds (a) 2018-2025 (b) 2.02% 1.75%-2.75% 0.74%-4.625% 264.6 225.4 Notes Payable – Nonaffiliated (c) 2017-2022 2.15% 2.03%-2.19% 1.456%-1.81% 188.6 251.4 Spent Nuclear Fuel Obligation (e) 268.6 266.3 Other Long-term Debt 2018-2025 3.03% 2.82%-6.00% 2.15%-6.00% 214.3 215.5 Total Long-term Debt Outstanding $ 2,745.1 $ 2,471.4 OPCo Senior Unsecured Notes 2018-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,591.4 $ 1,590.2 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.3 Securitization Bonds 2018-2019 (d) 2.049% 2.049% 0.958%-2.049% 94.5 140.2 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.1 1.2 Total Long-term Debt Outstanding $ 1,719.3 $ 1,763.9 PSO Senior Unsecured Notes 2019-2046 4.80% 3.05%-6.625% 3.05%-6.625% $ 1,144.1 $ 1,143.2 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2019-2027 2.60% 2.584%-3.00% 1.92%-3.00% 129.8 130.2 Total Long-term Debt Outstanding $ 1,286.5 $ 1,286.0 SWEPCo Senior Unsecured Notes 2017-2045 4.78% 2.75%-6.45% 2.75%-6.45% $ 2,110.7 $ 2,359.2 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 135.1 134.9 Notes Payable – Nonaffiliated (c) 2024-2032 5.20% 4.58%-6.37% 4.58%-6.37% 72.1 75.3 Other Long-term Debt 2017-2023 3.00% 2.925%-4.28% 2.346%-4.28% 124.0 109.7 Total Long-term Debt Outstanding $ 2,441.9 $ 2,679.1 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (f) 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 7 for additional information. Long-term debt outstanding as of December 31, 2017 is payable as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 1,753.7 $ 266.1 $ 50.0 $ 249.2 $ 474.7 $ 397.0 $ 0.5 $ 3.7 2019 2,307.9 501.1 85.0 305.4 535.2 48.0 375.5 457.2 2020 1,322.0 377.7 — 90.3 26.4 0.1 13.2 118.7 2021 1,352.9 66.2 50.0 393.0 49.9 500.1 250.5 3.7 2022 1,318.4 493.1 104.0 26.0 3.5 0.1 0.5 278.7 After 2022 13,265.7 1,970.5 2,286.0 2,951.0 1,673.9 782.9 652.5 1,594.9 Principal Amount 21,320.6 3,674.7 2,575.0 4,014.9 2,763.6 1,728.2 1,292.7 2,456.9 Unamortized Discount, Net and Debt Issuance Costs (147.3 ) (25.4 ) (24.6 ) (34.8 ) (18.5 ) (8.9 ) (6.2 ) (15.0 ) Total Long-term Debt Outstanding $ 21,173.3 $ 3,649.3 $ 2,550.4 $ 3,980.1 $ 2,745.1 $ 1,719.3 $ 1,286.5 $ 2,441.9 In January and February 2018 , I&M retired $14 million and $2 million , respectively, of Notes Payable related to DCC Fuel. In January 2018 , AEP Texas retired $96 million of Securitization Bonds. In January 2018 , OPCo retired $23 million of Securitization Bonds. In January 2018 , SWEPCo issued $450 million of 3.85% Senior Unsecured Notes due in 2048 . In January 2018 , Transource Energy issued $2 million of variable rate Other Long-term Debt due in 2020 . In February 2018 , APCo retired $12 million of Securitization Bonds. In February 2018 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 2017 , trustees held, on behalf of AEP, $678 million of their reacquired Pollution Control Bonds. Of this total, $104 million and $345 million related to APCo and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture 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. AEPTCo’s contractually-defined priority debt was 0.6% of consolidated tangible net assets as of December 31,2017. 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 also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2017 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $11.4 billion . The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2017 , the amount of any such restrictions was as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Restricted Retained Earnings $ 1,375.6 (a) $ 219.6 $ — $ — $ 416.2 $ — $ 173.5 $ 470.6 (a) Includes the restrictions of consolidated and unconsolidated subsidiaries. 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 method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2017 , AEP had $7.3 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.2 billion , $1.1 billion and $1.1 billion of dividends to common shareholders for the years ended December 31, 2017 , 2016 and 2015 , respectively. Lines of Credit and Short-term Debt (Applies to AEP and SWEPCo) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2017 , AEP had a credit facility for $3 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2017 was $1.6 billion and the weighted average interest rate of commercial paper outstanding during 2017 was 1.25% . AEP’s outstanding short-term debt was as follows: December 31, 2017 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 718.0 1.22 % $ 673.0 0.70 % AEP Commercial Paper 898.6 1.85 % 1,040.0 1.02 % SWEPCo Notes Payable 22.0 2.92 % — — % Total Short-term Debt $ 1,638.6 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. 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, a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries, and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2017 and 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 are described in the following tables: Year Ended December 31, 2017 : Maximum Average Net Loans to 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 December 31, 2017 Limit (in millions) AEP Texas $ 296.0 $ 451.7 $ 194.8 $ 264.6 $ 103.5 $ 400.0 AEPTCo 467.2 268.0 180.5 119.8 109.2 795.0 (a) APCo 231.5 160.7 144.3 30.0 (162.5 ) 600.0 I&M 367.4 12.6 204.9 12.6 (199.2 ) 500.0 OPCo 280.6 56.2 137.0 27.9 (87.8 ) 400.0 PSO 185.2 — 119.3 — (149.6 ) 300.0 SWEPCo 187.5 178.6 95.5 169.5 (118.7 ) 350.0 Year Ended December 31, 2016 : Maximum Average Net Loans to 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 December 31, 2016 Limit (in millions) AEP Texas $ 176.9 $ 138.9 $ 87.5 $ 79.8 $ (174.5 ) $ 400.0 AEPTCo 363.4 82.0 153.7 — 14.6 49.8 795.0 (a) APCo 286.9 25.7 148.0 24.8 (55.5 ) 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above tables does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary AEP Texas North Generation Company LLC (TNGC) and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP are participants in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2017 and 2016 are included in Advances to Affiliates on each subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity is described in the following tables: Year Ended December 31, 2017 : Maximum Maximum Average Average Net Loans to Borrowings from Loans to the Borrowings from Loans to the the Nonutility the Nonutility Nonutility the Nonutility Nonutility Money Pool as of Company Money Pool Money Pool Money Pool Money Pool December 31, 2017 (in millions) AEP Texas $ — $ 8.6 $ — $ 8.3 $ 8.4 SWEPCo — 2.0 — 2.0 2.0 Year Ended December 31, 2016 : Maximum Maximum Average Average Net Loans to Borrowings from Loans to the Borrowings from Loans to the the Nonutility the Nonutility Nonutility the Nonutility Nonutility Money Pool as of Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 (in millions) AEP Texas (a) $ 12.5 $ 27.0 $ 12.0 $ 12.3 $ 8.6 SWEPCo — 2.0 — 2.0 2.0 (a) Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information. AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. In January 2017, management removed AEP Texas from the direct financing relationship with AEP to better reflect current business operations. The amounts of outstanding loans to (borrowings from) AEP as of December 31, 2017 and 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each Registrant Subsidiaries’ balance sheets. The direct borrowing and lending activity with AEP are described in the following tables: Year Ended December 31, 2017 : Borrowings from Loans to Authorized Maximum Maximum Average Average AEP as of AEP as of Short-term Borrowings Loans Borrowings Loans December 31, December 31, Borrowing Company from AEP to AEP from AEP to AEP 2017 2017 Limit (in millions) AEP Texas $ — $ — $ — $ — $ — $ — $ — AEPTCo 4.1 151.9 1.1 39.3 1.1 22.5 75.0 (b) Year Ended December 31, 2016 : Borrowings from Loans to Authorized Maximum Maximum Average Average AEP as of AEP as of Short-term Borrowings Loans Borrowings Loans December 31, December 31, Borrowing Company from AEP to AEP from AEP to AEP 2016 2016 Limit (in millions) AEP Texas (a) $ 55.0 $ 5.0 $ 42.5 $ 5.0 $ — $ 5.0 $ — AEPTCo 5.6 170.4 1.0 35.7 1.0 14.2 75.0 (b) (a) Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information. (b) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Years Ended December 31, 2017 2016 2015 Maximum Interest Rate 1.85 % 1.02 % 0.87 % Minimum Interest Rate 0.92 % 0.69 % 0.37 % 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 for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2017 2016 2015 2017 2016 2015 AEP Texas 1.29 % 0.88 % 0.46 % 1.26 % 0.72 % 0.52 % AEPTCo 1.36 % 0.85 % 0.46 % 1.27 % 0.83 % 0.49 % APCo 1.28 % 0.80 % 0.53 % 1.29 % 0.82 % 0.47 % I&M 1.27 % 0.80 % 0.49 % 1.29 % 0.80 % 0.48 % OPCo 1.37 % 0.85 % — % 0.98 % 0.74 % 0.48 % PSO 1.32 % 0.96 % 0.49 % — % 0.83 % 0.48 % SWEPCo 1.28 % 0.79 % 0.53 % 0.98 % 0.90 % 0.48 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool are summarized in the following tables: Year Ended December 31, 2017 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas — % — % 1.85 % — % — % 1.32 % SWEPCo — % — % 1.85 % — % — % 1.32 % Year Ended December 31, 2016 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas 1.11 % 0.97 % 1.02 % 0.75 % 1.00 % 0.86 % SWEPCo — % — % 1.02 % 0.69 % — % 0.82 % Year Ended December 31, 2015 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas 1.14 % 0.64 % — % — % 0.76 % — % SWEPCo — % — % 0.87 % 0.37 % — % 0.48 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following tables: Year Ended December 31, 2017 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Company AEP AEP AEP AEP AEP AEP AEP Texas — % — % — % — % — % — % AEPTCo 1.85 % 0.92 % 1.85 % 0.92 % 1.33 % 1.36 % Year Ended December 31, 2016 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Company AEP AEP AEP AEP AEP AEP AEP Texas 0.98 % 0.69 % 1.02 % 0.99 % 0.83 % 1.00 % AEPTCo 1.02 % 0.69 % 1.02 % 0.69 % 0.83 % 0.87 % Year Ended December 31, 2015 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Company AEP AEP AEP AEP AEP AEP AEP Texas 0.87 % 0.37 % — % — % 0.48 % — % AEPTCo 0.87 % 0.37 % 0.87 % 0.37 % 0.48 % 0.47 % Interest expense and interest income related to the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Expense and Interest Income, respectively, on each of the Registrant Subsidiaries’ statements of income. The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2017 , 2016 and 2015 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . 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: Years Ended December 31, 2017 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.22 % 0.70 % 0.30 % Net Uncollectible Accounts Receivable Written Off $ 23.4 $ 23.7 $ 34.1 December 31, 2017 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 925.5 $ 945.0 Short-term – Securitized Debt of Receivables 718.0 673.0 Delinquent Securitized Accounts Receivable 41.1 42.7 Bad Debt Reserves Related to Securitization 28.7 27.7 Unbilled Receivables Related to Securitization 303.2 322.1 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 and AEP Texas) 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 were as follows: December 31, Company 2017 2016 (in millions) APCo $ 136.2 $ 142.0 I&M 136.5 136.7 OPCo 367.4 388.3 PSO 115.1 110.4 SWEPCo 138.2 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 5.6 $ 6.7 $ 7.6 I&M 6.7 7.1 8.4 OPCo 21.7 28.9 30.7 PSO 7.0 6.2 5.8 SWEPCo 7.2 6.9 7.0 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 1,372.8 $ 1,412.5 $ 1,453.8 I&M 1,612.9 1,596.2 1,553.0 OPCo 2,339.0 2,633.0 2,569.4 PSO 1,337.0 1,269.3 1,326.1 SWEPCo 1,563.4 1,531.7 1,597.8

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Stock-based Compensation	STOCK-BASED COMPENSATION The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries. Awards under AEP’s long-term incentive plan may be granted to employees and directors. The Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2017 , 9,011,946 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award that settles in AEP stock, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. Cash settled awards do not reduce the aggregate amount authorized under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. Performance Units Performance units granted prior to 2017 are settled in cash rather than AEP common stock and do not reduce the aggregate share authorization. These performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance units granted in 2017 will be settled in AEP common stock and will reduce the aggregate share authorization. In all cases the number of performance units held at the end of the three year performance period is multiplied by the performance score for such period to determine the actual number of performance units realized. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee). Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, a portion or all of their performance units are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock. AEP career shares are settled in AEP common stock after the participant’s termination of employment. AEP career shares are recorded in Paid in Capital on the balance sheet. Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units. Management records compensation cost for performance units over an approximately three-year vesting period. The liability for the pre 2017 performance units is recorded in Employee Benefits and Pension Obligations on the balance sheet and is adjusted for changes in value. Performance units settled in shares are recorded as mezzanine equity on the balance sheet and compensation cost is calculated at fair value using two metrics. Half is based on the total shareholder return measure, which is determined based on a third party Monte Carlo valuation. That metric doesn’t change over the three year vesting period. The other half is based on a three year cumulative earnings per share metric which is adjusted quarterly for changes in performance relative to a target approved by the HR Committee. Monte Carlo Valuation AEP engaged a third party for a Monte Carlo valuation to calculate half of the fair value for the performance units awarded during 2017. The valuation used a lattice model and the expected volatility assumption used was the historical volatilities for AEP and the members of their peer group over the last 2.86 years (period from award date to vesting date). The range of expected volatilities was 15.65% to 27.19% with an average expected volatility of 19.07% . The dividend rates used were 0% which is the equivalent to reinvesting dividends. The risk-free rate used was 1.44% , which was interpolated between the two year rate of 1.21% and three year rate of 1.48% since 2.86 years was the vesting period from award date to vesting date. The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP career shares for the years ended December 31, 2017 , 2016 and 2015 as follows: Years Ended December 31, Performance Units 2017 2016 2015 Awarded Units (in thousands) (a) 590.7 597.4 575.0 Weighted Average Unit Fair Value at Grant Date $ 69.78 $ 62.77 $ 59.19 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2017 2016 2015 Awarded Units (in thousands) (c) 74.6 89.2 103.6 Weighted Average Fair Value at Grant Date $ 72.35 $ 63.83 $ 54.35 Vesting Period (in years) (b) (b) (b) (a) Awarded units in 2017 are mezzanine equity awards and awarded units in 2016 and 2015 are liability awards. (b) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends. (c) In 2017 the awarded dividends were a mix of equity awards and liability awards, while they were all liability awards in 2016 and 2015. Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all performance periods were dependent on two equally-weighted performance measures: (a) three -year total shareholder return measured relative to a peer group of similar companies (b) three -year cumulative earnings per share measured relative to a target approved by the HR Committee. The certified performance scores and units earned for the three-year periods ended December 31, 2017 , 2016 and 2015 were as follows: Years Ended December 31, Performance Units 2017 2016 2015 Certified Performance Score 164.8 % 163.9 % 176.3 % Performance Units Earned 956,055 1,111,966 1,202,107 Performance Units Mandatorily Deferred as AEP Career Shares 20,213 9,963 41,707 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 47,177 51,684 54,074 Performance Units to be Settled in Cash 888,665 1,050,319 1,106,326 The settlements for the years ended December 31, 2017 , 2016 and 2015 were as follows: Years Ended December 31, Performance Units and AEP Career Shares 2017 2016 2015 (in millions) Cash Settlements for Performance Units $ 64.9 $ 62.7 $ 48.1 Cash Settlements for Career Share Distributions — 9.1 3.0 AEP Common Stock Settlements for Career Share Distributions 0.4 — — Restricted Stock Units The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting, except that RSUs granted prior to 2017 that vest to AEP’s executive officers are settled in cash. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. For RSUs settled in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs settled in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting is determined by multiplying the number of RSUs vested by the 20 -day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 72 months from the grant date. In 2010, the HR Committee granted a total of 165,520 RSUs to four Chief Executive Officer succession candidates as a retention incentive for these candidates. These grants vested in three approximately equal installments in August 2013, August 2014 and August 2015. The HR Committee awarded RSUs, including additional units awarded as dividends, for the years ended December 31, 2017 , 2016 and 2015 as follows: Years Ended December 31, Restricted Stock Units 2017 2016 2015 Awarded Units (in thousands) 255.8 242.0 397.5 Weighted Average Grant Date Fair Value $ 65.26 $ 62.88 $ 58.56 The total fair value and total intrinsic value of restricted stock units vested during the years ended December 31, 2017 , 2016 and 2015 were as follows: Years Ended December 31, Restricted Stock Units 2017 2016 2015 (in millions) Fair Value of Restricted Stock Units Vested $ 16.1 $ 16.4 $ 18.3 Intrinsic Value of Restricted Stock Units Vested (a) 20.0 21.0 24.2 (a) Intrinsic value is calculated as market price at exercise date. A summary of the status of AEP’s nonvested RSUs as of December 31, 2017 and changes during the year ended December 31, 2017 are as follows: Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2017 603.6 $ 57.54 Granted 255.8 65.26 Vested (295.1 ) 54.72 Forfeited (34.7 ) 61.53 Nonvested as of December 31, 2017 529.6 62.13 The total aggregate intrinsic value of nonvested RSUs as of December 31, 2017 was $39 million and the weighted average remaining contractual life was 1.6 years . Other Stock-Based Plans AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to Non-Employee Directors are fully vested upon grant date. Stock units are settled in cash upon termination of board service or up to 10 years later if the participant so elects. Cash settlements for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investments that are similar to the investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20 -day average closing price of AEP common stock on the valuation date. For 2017 , 2016 and 2015 , cash settlements for stock unit distributions were immaterial. The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2017 , 2016 and 2015 as follows: Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2017 2016 2015 Awarded Units (in thousands) 14.8 19.1 24.9 Weighted Average Grant Date Fair Value $ 70.79 $ 64.96 $ 55.46 Share-based Compensation Plans Compensation cost for share-based payment arrangements, the actual tax benefit from the tax deductions for compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2017 , 2016 and 2015 were as follows: Years Ended December 31, Share-based Compensation Plans 2017 2016 2015 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 79.5 $ 66.5 $ 63.8 Actual Tax Benefit (b) 18.9 23.3 22.3 Total Compensation Cost Capitalized 26.4 20.8 20.3 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income. (b) In December 2017, Tax Reform modified Section 162(m) of the Internal Revenue Code. Beginning after 2017, AEP can no longer deduct compensation expense in excess of $1 million for certain named executive officers. This will reduce the tax benefit going forward. As of December 31, 2017 , there was $64 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP and Prior Plan. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units are adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.35 years . Under the 2015 LTIP and Prior Plan, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. In 2017, AEP used a combination of all three to fulfill share commitments. AEP’s current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset AEP’s tax withholding obligation.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 14 . Power Coordination Agreement (PCA), Bridge Agreement and Power Supply Agreement (PSA) (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo) Effective January 1, 2014, the FERC approved the following agreements. • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. Further, the Restated and Amended PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR committed to use its capacity to help meet the PJM capacity obligations of member companies through the PJM planning year that ended May 31, 2015. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The following tables show the revenues derived from direct sales to affiliates, auction sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2017 , 2016 and 2015 : Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2017 Direct Sales to East Affiliates $ — $ — $ 130.4 $ — $ — $ — $ — Direct Sales to West Affiliates — — — 3.8 — — — Auction Sales to OPCo (a) — — 1.0 — — — — Direct Sales to AEPEP 63.6 — — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales — 572.0 34.1 (4.4 ) 6.2 — 24.2 Other Revenues 2.1 8.5 6.5 2.4 18.2 4.3 1.9 Total Affiliated Revenues $ 65.7 $ 580.5 $ 172.0 $ 1.8 $ 24.4 $ 4.3 $ 25.9 Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ — $ — $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — — — 3.7 Auction Sales to OPCo (a) — — 9.2 12.0 — — — Direct Sales to AEPEP 73.9 — — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales — 366.1 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 1.8 — 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 75.7 $ 366.1 $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ — $ — $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) — — 10.6 17.1 — — — Direct Sales to AEPEP 76.9 — — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales — 225.6 0.7 8.4 35.5 0.2 15.2 Other Revenues 1.6 — 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 78.5 $ 225.6 $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2017 , 2016 and 2015 . AEP Texas, AEPTCo, APCo and SWEPCo did not purchase any power from affiliates for the years ended December 31, 2017 , 2016 and 2015 . Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2017 Auction Purchases from AEPEP (a) $ — $ 96.5 $ — Auction Purchases from AEP Energy (a) — 5.5 — Auction Purchases from AEPSC (a) — 6.5 — Direct Purchases from AEGCo 223.9 — — Total Affiliated Purchases $ 223.9 $ 108.5 $ — Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates $ — $ — $ 3.7 Auction Purchases from AEPEP (a) — 110.1 — Auction Purchases from AEP Energy (a) — 7.7 — Auction Purchases from AEPSC (a) — 24.1 — Direct Purchases from AEGCo 228.6 — — Total Affiliated Purchases $ 228.6 $ 141.9 $ 3.7 Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2015 Direct Purchases from AGR (b) $ — $ 269.2 $ — Auction Purchases from AEPEP (a) — 225.2 — Auction Purchases from AEPSC (a) — 32.7 — Direct Purchases from AEGCo 232.1 — — Total Affiliated Purchases $ 232.1 $ 527.1 $ — (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Amount excludes $31 million in 2015 which is now presented as Generation Deferrals on the Statement of Income. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. Transmission Agreement (TA) and Transmission Coordination Agreement (TCA) (Applies to all Registrant Subsidiaries except AEP Texas) APCo, I&M, KGPCo, KPCo, OPCo and WPCo (AEP East Companies) are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. The following table shows the net charges recorded by APCo, I&M and OPCo for the years ended December 31, 2017 , 2016 and 2015 related to the TA: Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 158.2 $ 103.2 $ 92.7 I&M 103.8 53.0 38.0 OPCo 248.6 143.6 81.0 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, Company 2017 2016 2015 (in millions) PSO $ 56.0 $ 19.6 $ 15.0 SWEPCo 6.6 (19.6 ) (15.0 ) The net revenues shown above are recorded in Sales to AEP Affiliates on the statements of income and the net expenses are recorded in Other Operation expenses on the statements of income. AEPTCo is a load serving entity within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. AEPTCo recorded affiliated transmission revenues related to the TA and TCA in Sales to AEP Affiliates on the statements of income. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. ERCOT Transmission Service Charges (Applies to AEP Texas) Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $30 million , $29 million and $27 million for transmission services in 2017 , 2016 and 2015 , respectively. The billings are recorded in Other Operation expenses on AEP Texas’ statements of income. Oklaunion PPA between AEP Texas and AEPEP (Applies to AEP Texas) On January 1, 2007, AEP Texas began a PPA with an affiliate, AEPEP, whereby AEP Texas agrees to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest ( 54.69% ) in the Oklaunion Plant. This PPA is effective through December 2027. AEPEP is to pay AEP Texas for the capacity and associated energy delivered to the delivery point, the sum of fuel, operation and maintenance, depreciation, capacity and all taxes other than federal income taxes applicable. A portion of the payment is fixed and is payable regardless of the level of output. In the event AEP Texas or AEPEP terminate the PPA or the Oklaunion Plant is closed by a vote of its owners prior to December 2027, AEPEP will make a payment to AEP Texas equal to AEP Texas’s net book value of Oklaunion Plant at the time of such termination or plant closure. There are no penalties if AEP Texas fails to maintain a minimum availability level or exceeds a maximum heat rate level. The PPA was approved by the FERC. AEP Texas recognizes revenues for the fuel, operations and maintenance and all other taxes as-billed. Revenue is recognized for the capacity and depreciation billed to AEPEP, on a straight-line basis over the term of the PPA as these represent the minimum payments due. AEP Texas recorded revenue of $64 million , $74 million and $77 million from AEPEP for the years ended December 31, 2017 , 2016 and 2015 , respectively. These amounts are included in Sales to AEP Affiliates on AEP Texas’ statements of income. Joint License Agreement (Applies to AEPTCo, I&M, KPCo, OPCo and PSO) AEPTCo entered into 50-year joint license agreement with I&M, KPCo, OPCo and PSO, respectively, allowing either party to occupy the granting party’s facilities or real property. After the expiration of the agreement, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. For the years ended December 31, 2017 , 2016 and 2015 , AEPTCo recorded the following costs in Other Operation expense related to these agreements: Years Ended December 31, Billing Company 2017 2016 2015 (in millions) I&M $ 1.4 $ 0.8 $ 0.6 KPCo 0.2 0.1 — OPCo 2.4 2.3 2.0 PSO 0.3 0.2 0.3 I&M, KPCo, OPCo and PSO recorded income related to these agreements in Sales to AEP Affiliates on the statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. Unit Power Agreements (UPA) (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading costs in 2017 , 2016 and 2015 were as follows: Years Ended December 31, Company 2017 2016 2015 (in millions) I&M $ 10.2 $ 12.8 $ 15.8 I&M recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance costs in 2017 , 2016 and 2015 were as follows: Years Ended December 31, Company 2017 2016 2015 (in millions) I&M $ 1.3 $ 1.7 $ 2.0 PSO 0.5 0.6 0.2 SWEPCo 3.5 3.3 2.8 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2017 2016 2015 (in millions) AEGCo $ 15.3 $ 14.8 $ 16.1 AGR 0.1 0.3 4.9 APCo 37.2 36.9 37.7 KPCo 5.0 5.3 4.6 WPCo 5.0 4.8 — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — — 15.5 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses on the statement of income. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the year ended December 31, 2015 , I&M recorded expenses of $19 million for these activities. Central Machine Shop (Applies to APCo, I&M, PSO and SWEPCo) APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2017 2016 2015 (in millions) AEGCo $ — $ — $ 0.1 AGR 1.2 2.0 2.7 I&M 2.7 2.9 2.5 KPCo 1.8 1.5 1.3 PSO 1.1 0.5 0.2 SWEPCo 0.8 0.9 0.8 Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2017 , 2016 and 2015 : Sales Years Ended December 31, Company 2017 2016 2015 (in millions) AEP Texas $ 0.2 $ 0.3 $ 0.6 AEPTCo — — 0.2 APCo 3.5 4.5 9.4 I&M 5.0 5.2 3.0 OPCo 2.9 1.9 2.4 PSO 1.5 7.5 7.1 SWEPCo 0.5 1.0 0.8 Purchases Years Ended December 31, Company 2017 2016 2015 (in millions) AEP Texas $ 0.4 $ 0.7 $ 0.9 AEPTCo 9.1 6.5 0.4 APCo 0.9 1.5 8.6 I&M 3.5 2.7 8.1 OPCo 1.6 1.7 2.1 PSO 0.2 3.2 0.6 SWEPCo 0.4 6.5 7.4 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2017
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC, OVEC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities (Applies to all Registrants except AEPTCo and PSO) Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2017 , 2016 and 2015 were $137 million , $162 million and $152 million , respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2017 , 2016 and 2015 were $136 million , $101 million and $115 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1 billion and $1.2 billion as of December 31, 2017 and 2016 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $870 million and $1.1 billion as of December 31, 2017 and 2016 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $95 million and $140 million as of December 31, 2017 and 2016 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $38 million and $62 million as of December 31, 2017 and 2016 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $296 million and $319 million as of December 31, 2017 and 2016 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $282 million and $305 million as of December 31, 2017 and 2016 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately six lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2017 , 2016 and 2015 was $29 million , $28 million and $29 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $5 million and $45 million , in 2017 and 2016 , respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In 2016, AEP Renewables acquired solar projects that were funded only through participation in the AEP corporate borrowing program. As a result, management concluded that AEP Renewables was a VIE and that Energy Supply was the primary beneficiary due to its capacity to direct the most significant activities of the entity and it’s equity interest could potentially be significant. In the first quarter of 2017, AEP Renewables received a capital contribution of $140 million from Energy Supply. The capital contribution gave AEP Renewables sufficient equity at risk, which resulted in the definition of a VIE no longer being met. Energy Supply continues to consolidate AEP Renewables in accordance with other applicable accounting guidance for “Consolidation” due to its controlling financial interest as the owner of AEP Renewables. See the tables below for the classification of AEP Renewables’ assets and liabilities on the December 31, 2016 balance sheet. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2017 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel AEP Texas Transition Funding OPCo APCo (in millions) ASSETS Current Assets $ 56.3 $ 102.5 $ 191.7 $ 28.7 $ 22.3 Net Property, Plant and Equipment 113.2 179.9 — — — Other Noncurrent Assets 90.2 86.3 923.5 (a) 71.0 (b) 285.6 (c) Total Assets $ 259.7 $ 368.7 $ 1,115.2 $ 99.7 $ 307.9 LIABILITIES AND EQUITY Current Liabilities $ 49.1 $ 96.5 $ 260.9 $ 47.9 $ 27.6 Noncurrent Liabilities 211.0 272.2 836.1 50.5 278.4 Equity (0.4 ) — 18.2 1.3 1.9 Total Liabilities and Equity $ 259.7 $ 368.7 $ 1,115.2 $ 99.7 $ 307.9 (a) Includes an intercompany item eliminated in consolidation of $53.9 million . (b) Includes an intercompany item eliminated in consolidation of $33.3 million . (c) Includes an intercompany item eliminated in consolidation of $3.4 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2017 Other Consolidated VIEs AEP Credit Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 926.3 $ 178.7 $ 17.4 Net Property, Plant and Equipment — — 323.9 Other Noncurrent Assets 6.4 — 3.1 Total Assets $ 932.7 $ 178.7 $ 344.4 LIABILITIES AND EQUITY Current Liabilities $ 872.0 $ 36.4 $ 12.4 Noncurrent Liabilities 0.7 95.2 132.0 Equity 60.0 47.1 200.0 Total Liabilities and Equity $ 932.7 $ 178.7 $ 344.4 American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel AEP Texas Transition Funding OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 184.8 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — — Other Noncurrent Assets 89.8 116.2 1,149.4 (a) 117.1 (b) 309.0 (c) Total Assets $ 262.0 $ 485.6 $ 1,334.2 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 251.9 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 1,064.2 98.6 300.6 Equity 0.4 — 18.1 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 1,334.2 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . (b) Includes an intercompany item eliminated in consolidation of $55 million . (c) Includes an intercompany item eliminated in consolidation of $3.7 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2016 Other Consolidated VIEs AEP Credit Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — 313.0 130.4 Other Noncurrent Assets 10.3 1.1 5.4 9.0 Total Assets $ 956.0 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 97.3 134.4 11.3 Equity 78.0 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 171.7 $ 334.7 $ 139.4 Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. The operations of DHLC are governed by the lignite mining agreement among SWEPCo, CLECO and DHLC. SWEPCo and CLECO share the executive board seats and voting rights equally. In accordance with the lignite mining agreement, each entity is responsible for 50% of DHLC’s obligations, including debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2017 , 2016 and 2015 were $61 million , $65 million and $93 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2017 2016 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 11.8 11.8 15.7 15.7 SWEPCo’s Share of Obligations — 144.3 — 91.3 Total Investment in DHLC $ 19.4 $ 163.7 $ 23.3 $ 114.6 AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2017 , AEP’s ownership in OVEC was 43.47% . Parent owns 39.17% and OPCo owns 4.3% . APCo, I&M and OPCo are members to an intercompany power agreement. The Registrants’ power participation ratios are 15.69% for APCo, 7.85% for I&M and 19.93% for OPCo. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040 . AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2017 , OVEC’s outstanding indebtedness is approximately $1.4 billion . Although they are not an obligor or guarantor, the Registrants’ are responsible for their respective ratio of OVEC’s outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 . AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and its subsidiaries hold a significant variable interest in OVEC. Power to control decision making that significantly impact the economic performance of OVEC is shared amongst the owners through their representation on the Board of Directors and Operating Committee of OVEC. AEP’s investment in OVEC was: December 31, 2017 2016 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from AEP $ 4.4 $ 4.4 $ 4.4 $ 4.4 AEP’s Ratio of OVEC Debt (a) — 626.3 — 658.3 Total Investment in OVEC $ 4.4 $ 630.7 $ 4.4 $ 662.7 (a) Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt is $226 million , $113.1 million and $287.2 million for the year ended December 31, 2017 and $237.6 million , $118.9 million and $301.8 million for the year-ended December 31, 2016, respectively. The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2017 , 2016 and 2015 were: Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 101.0 $ 88.0 $ 87.2 I&M 50.5 44.0 43.7 OPCo 128.2 111.7 110.8 The amounts above are included in Purchased Electricity for Resale on the statements of income. AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series.” AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the FERC were held in March and April 2015. In April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the ALJ issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact the recovery of costs by the PATH Companies under their formula rates or the timing of the compliance filing required by the order, which was filed in March 2017, and updated in May 2017 and August 2017. As a result of the January 2017 FERC order, PATH-WV is required to refund certain amounts that have been collected under its formula rate in its 2018 Projected Transmission Revenue Requirement. PATH-WV will refund $11.4 million , including carrying charges, related to the January 2017 order in its 2018 Projected Transmission Revenue Requirement. AEP’s investment in PATH-WV was: December 31, 2017 2016 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.0 ) (2.0 ) (2.3 ) (2.3 ) Total Investment in PATH-WV $ 16.8 $ 16.8 $ 16.5 $ 16.5 As of December 31, 2017 , AEP’s $17 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2017 2016 2015 (in millions) AEP Texas $ 152.6 $ 142.3 $ 132.7 AEPTCo 188.9 131.1 108.4 APCo 268.8 244.2 227.5 I&M 176.0 147.7 139.5 OPCo 195.7 181.1 177.8 PSO 114.7 111.0 107.3 SWEPCo 150.7 147.0 141.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2017 2016 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) AEP Texas $ 24.2 $ 24.2 $ 22.9 $ 22.9 AEPTCo 25.1 25.1 23.0 23.0 APCo 37.0 37.0 36.7 36.7 I&M 26.8 26.8 24.2 24.2 OPCo 27.4 27.4 28.1 28.1 PSO 18.7 18.7 16.0 16.0 SWEPCo 20.8 20.8 21.8 21.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2017 , 2016 and 2015 were $224 million , $229 million and $232 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2017 and 2016 was $23 million and $22 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 . The assets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 for additional information.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2017 and 2016 : December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 20,406.5 (a) $ — $ — $ 6,446.9 $ 4,445.9 $ — $ 1,577.2 $ 4,624.9 (a) Transmission 18,942.3 3,053.6 5,336.1 3,019.9 1,504.0 2,419.2 858.8 1,679.8 Distribution 19,865.9 3,718.6 — 3,763.8 2,069.3 4,626.4 2,445.1 2,095.8 Other 3,224.8 457.6 130.0 399.5 552.3 485.5 282.0 416.8 CWIP 3,972.6 (a) 834.4 1,312.7 483.0 460.2 410.1 111.3 220.7 (a) Less: Accumulated Depreciation 16,906.7 1,399.4 170.4 3,891.1 3,011.7 2,183.9 1,393.6 2,520.5 Total Regulated Property, Plant and Equipment - Net 49,505.4 6,664.8 6,608.4 10,222.0 6,020.0 5,757.3 3,880.8 6,517.5 Nonregulated Property, Plant and Equipment - Net 756.1 160.3 1.4 23.1 30.4 9.5 5.4 114.5 Total Property, Plant and Equipment - Net $ 50,261.5 $ 6,825.1 $ 6,609.8 $ 10,245.1 $ 6,050.4 $ 5,766.8 $ 3,886.2 $ 6,632.0 December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (a) $ — $ — $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (a) Transmission 16,658.6 2,623.6 3,973.5 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,527.2 — 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 432.1 98.3 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (a) 385.0 981.3 390.3 654.2 221.5 148.2 113.7 (a) Less: Accumulated Depreciation 16,101.5 1,354.4 99.6 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 5,613.5 4,953.5 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 167.2 1.1 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (b) $ 5,780.7 $ 4,954.6 $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.3% - 3.7% 20 - 132 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 Transmission 1.6% - 2.7% 15 - 100 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 Distribution 2.7% - 3.7% 5 - 156 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 Other 2.3% - 9.2% 5 - 84 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 AEP Texas 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 1.7% 45 - 81 1.8% 45 - 81 1.8% 45 - 81 Distribution 3.6% 7 - 70 3.3% 7 - 70 3.3% 7 - 70 Other 8.7% 5 - 50 8.3% 5 - 50 9.7% 5 - 50 AEPTCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 1.7% 20 - 100 1.6% 20 - 100 1.4% 20 - 75 APCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 112 3.1% 35 - 121 3.1% 35 - 121 Transmission 1.6% 15 - 68 1.5% 15 - 68 1.6% 15 - 68 Distribution 3.7% 10 - 57 3.7% 10 - 57 3.6% 10 - 57 Other 6.5% 5 - 55 6.0% 5 - 55 8.3% 5 - 55 I&M 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 20 - 132 2.4% 59 - 132 2.5% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.7% 10 - 70 2.8% 10 - 70 2.8% 10 - 70 Other 8.4% 5 - 45 8.6% 5 - 45 11.8% 5 - 45 OPCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 5 - 57 2.8% 7 - 57 2.8% 7 - 57 Other 6.2% 5 - 50 5.9% 5 - 50 7.2% 5 - 50 PSO 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 2.4% 35 - 85 1.7% 35 - 70 Transmission 2.2% 45 - 100 2.2% 45 - 100 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.7% 27 - 156 2.5% 7 - 65 Other 7.4% 5 - 84 6.4% 5 - 84 4.6% 5 - 40 SWEPCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.3% 40 - 70 2.1% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 73 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.7% 25 - 70 2.6% 25 - 65 2.6% 25 - 65 Other 7.2% 5 - 55 6.8% 5 - 51 5.5% 5 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP, AEP Texas and SWEPCo. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of AEPTCo, APCo, I&M, OPCo and PSO for 2017 , 2016 and 2015 . 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% - 5.1% 15 - 66 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 Transmission 0.2% 40 2.3% 43 - 55 2.3% 43 - 55 Distribution 2.3% 40 1.3% 40 - 50 —% 0 - 0 Other 12.1% 5 - 50 (a) 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) (Applies to all Registrants except AEPTCo) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2017 and 2016 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.30 billion and $1.24 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2017 and 2016 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $2.22 billion and $1.95 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The following is a reconciliation of the 2017 and 2016 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2016 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2017 (in millions) AEP (a)(b)(c)(d) $ 1,934.9 $ 90.9 $ 2.4 $ (104.5 ) $ 82.0 $ 2,005.7 AEP Texas (a)(d) 25.5 1.2 — (0.1 ) 0.1 26.7 APCo (a)(d) 127.1 7.0 — (21.7 ) 12.6 125.0 I&M (a)(b)(d) 1,258.1 55.9 — (0.1 ) 7.9 1,321.8 OPCo (d) 1.7 0.1 — (0.1 ) — 1.7 PSO (a)(d) 53.4 3.1 — (0.5 ) (2.0 ) 54.0 SWEPCo (a)(c)(d) 156.5 8.3 — (0.3 ) 4.7 169.2 Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (a)(b)(c)(d) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (e) $ 66.4 $ 1,934.9 AEP Texas (a)(d) 24.0 1.1 — (0.1 ) 0.5 25.5 APCo (a)(d) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (a)(b)(d) 1,253.8 55.6 — (62.6 ) (e) 11.3 1,258.1 OPCo (d) 1.4 0.1 0.2 — — 1.7 PSO (a)(d) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (a)(c)(d) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.30 billion and $1.24 billion as of December 31, 2017 and 2016 , respectively. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2017 2016 2015 (in millions) AEP $ 93.7 $ 113.2 $ 131.9 AEP Texas 6.8 9.2 6.7 AEPTCo 52.3 52.3 53.0 APCo 9.2 11.7 13.8 I&M 11.1 15.3 11.6 OPCo 6.4 6.0 8.8 PSO 0.5 6.2 8.8 SWEPCo 2.4 11.0 26.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2017 2016 2015 (in millions) AEP $ 48.6 $ 51.7 $ 61.3 AEP Texas 6.8 5.9 4.5 AEPTCo 20.2 15.6 17.7 APCo 5.3 6.3 6.9 I&M 6.7 7.2 5.0 OPCo 3.8 3.3 4.8 PSO 1.1 3.4 5.0 SWEPCo 2.1 6.9 14.8 Jointly-owned Electric Facilities (Applies to AEP, AEP Texas, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2017 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a)(k)(l) Coal 83.5 % $ 2.1 $ 4.2 $ 0.1 J.M. Stuart Generating Station (b)(k) Coal 26.0 % — — — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 343.1 5.3 214.2 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 589.8 7.8 406.3 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 456.4 1.9 254.6 Turk Generating Plant (j)(n) Coal 73.3 % 1,580.4 3.2 166.6 Transmission NA (d) 62.7 0.3 46.1 Total $ 3,399.3 $ 31.6 $ 1,169.5 AEP Texas Oklaunion Generating Station, Unit 1 (h) Coal 54.7 % $ 350.7 $ 1.3 $ 194.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 1,093.9 $ 28.2 $ 562.6 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.7 $ 0.6 $ 60.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 343.1 $ 5.3 $ 214.2 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 589.8 7.8 406.3 Turk Generating Plant (j)(n) Coal 73.3 % 1,580.4 3.2 166.6 Total $ 2,878.1 $ 25.2 $ 868.7 Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a)(k)(l) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b)(k) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c)(k)(m) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 AEP Texas Oklaunion Generating Station, Unit 1 (h) Coal 54.7 % $ 349.6 $ 0.9 $ 186.5 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 (a) Operated by AGR. (b) Operated by Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. J.M. Stuart Generating Station and Wm. H. Zimmer Generating Station were impaired as of November 30, 2016. See the “Impairments” section of Note 7 . (l) In accordance with the Asset Purchase Agreement between AGR and Dynegy Corporation dated February 2017, AGR acquired Dynegy Corporation’s 40% ownership interest in Conesville Generating Station, Unit 4. Subsequent to this transaction, AGR’s ownership percentage in Conesville Generating Station, Unit 4 is 83.5% . (m) In accordance with the Asset Purchase Agreement between AGR and Dynegy Corporation dated February 2017, Dynegy Corporation acquired AGR’s 25.4% ownership interest in Wm. H. Zimmer Generating Station. Subsequent to this transaction, AGR has no ownership interest in Wm. H. Zimmer Generating Station. See the “Dispositions” section of Note 7 . (n) In December 2017, SWEPCo recorded a $15 million pretax impairment related to the Louisiana jurisdictional share of Turk Plant. Amount reflects the impact of the impairment. See the “Impairments” section of Note 7 . NA Not applicable.

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2017 Total Revenues $ 3,933.3 $ 343.6 $ 152.7 $ 792.8 $ 560.5 $ 746.1 $ 304.1 $ 401.3 Operating Income 1,097.1 83.2 90.4 220.2 118.7 150.7 20.8 53.7 Net Income 594.2 33.3 57.0 110.6 68.4 86.2 4.8 17.3 Earnings Attributable to Common Shareholders 592.2 NA NA NA NA NA NA 16.3 June 30, 2017 Total Revenues $ 3,576.5 $ 389.5 $ 229.4 $ 675.3 $ 467.3 $ 663.9 $ 344.7 $ 424.7 Operating Income 744.7 109.7 165.4 127.4 35.2 119.6 46.1 75.0 Net Income 376.2 49.0 107.4 52.1 10.5 62.3 20.4 25.1 Earnings Attributable to Common Shareholders 375.0 NA NA NA NA NA NA 24.5 September 30, 2017 Total Revenues $ 4,104.7 $ 431.2 $ 167.3 $ 719.3 $ 557.7 $ 742.0 $ 442.8 $ 517.6 Operating Income 986.5 129.7 95.1 173.0 115.1 154.5 86.8 137.0 Net Income 556.7 64.3 59.9 86.0 64.9 82.6 46.2 84.1 Earnings Attributable to Common Shareholders 544.7 NA NA NA NA NA NA 73.1 December 31, 2017 Total Revenues $ 3,810.4 $ 374.1 $ 173.8 $ 746.8 $ 535.7 $ 731.9 $ 335.6 $ 436.3 Operating Income 742.2 97.1 96.9 174.9 84.3 145.4 21.2 42.0 Net Income 401.8 163.9 61.8 82.6 42.9 92.8 0.6 11.0 Earnings Attributable to Common Shareholders 400.7 NA NA NA NA NA NA 10.8 NA Not applicable. Quarterly Periods Ended: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 330.5 $ 79.6 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 82.4 34.8 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 35.0 — — — — — — Income (Loss) from Discontinued Operations, Net of Tax — (1.3 ) (c) — — — — — — Net Income 503.1 33.7 25.8 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 365.0 $ 153.1 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 103.4 108.1 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 49.7 — — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) (0.7 ) (c) — — — — — — Net Income 503.9 49.0 74.8 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 403.9 $ 125.3 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 112.4 76.4 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) 55.5 — — — — — — Income (Loss) from Discontinued Operations, Net of Tax — (47.4 ) (c) — — — — — — Net Income (Loss) (764.2 ) (b) 8.1 52.4 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 362.0 $ 120.0 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 81.4 60.8 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 55.2 — — — — — — Income from Discontinued Operations, Net of Tax — 0.6 (c) — — — — — — Net Income 375.2 55.8 39.7 65.3 38.5 37.5 2.6 16.5 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for certain merchant generation assets (see Note 7 ). (c) Includes the transfer of the Wind Farms (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2017 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 592.2 $ 375.0 $ 544.7 $ 400.7 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.20 0.76 1.11 0.81 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.20 0.76 1.10 0.81 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 (a) Relates to impairments for certain merchant generation assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ).

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2017
Goodwill and Other Intangible Assets	GOODWILL AND OTHER INTANGIBLE ASSETS The disclosures in this note apply to AEP only. Goodwill The changes in AEP’s carrying amount of goodwill for the years ended December 31, 2017 and 2016 by operating segment are as follows: Corporate and Other Generation & Marketing AEP Consolidated (in millions) Balance as of December 31, 2015 $ 37.1 $ 15.4 $ 52.5 Impairment Losses — — — Balance as of December 31, 2016 37.1 15.4 52.5 Impairment Losses — — — Balance as of December 31, 2017 $ 37.1 $ 15.4 $ 52.5 In the fourth quarters of 2017 and 2016 , annual impairment tests were performed. The fair values of the reporting units with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. AEP does not have any accumulated impairment on existing goodwill. Other Intangible Assets Amortization of intangible assets was $2 million and $3 million for the years ended December 31, 2016 and 2015 , respectively. Acquired intangible assets were fully amortized as of December 31, 2016. The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows: December 31, 2016 Amortization Life Gross Carrying Amount Accumulated Amortization (in years) (in millions) Acquired Customer Contracts 5 $ 58.3 $ 58.3

Organization and Summary of S29

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, Operating Agreement, Transmission Agreement and Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA and the Bridge Agreement, see Note 16 - Related Party Transactions for additional information.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries and Transition Funding (a substantially-controlled VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. AEP, AEP Texas, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Accounting for the Impacts of Tax Reform Given the significance of the legislative changes resulting from Tax Reform, the timing of its enactment and the widespread applicability to registrants, the SEC staff recognized the potential challenges faced by registrants when reflecting the effects of Tax Reform in their 2017 financial statements. Accordingly, the SEC staff issued Staff Accounting Bulletin 118 (SAB 118) in December 2017, which provides for a one year measurement period to complete the accounting for Tax Reform. The Registrants have made reasonable estimates for the measurement and accounting for the impacts of Tax Reform and these estimates are reflected in the December 31, 2017 financial statements as provisional amounts. While the Registrants were able to make reasonable estimates of the impact of Tax Reform, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative temporary differences or as a result of additional guidance or technical corrections that may be issued by the IRS or regulatory state commissions that impacts management’s interpretation and assumptions utilized. See “Federal Tax Reform” section of Note 12 for additional information.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash for Securitized Funding	Restricted Cash (Applies to AEP, AEP Texas, APCo and OPCo) Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.
Other Temporary Investments	Other Temporary Investments (Applies to AEP) Other Temporary Investments include securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances and Renewable Energy Credits	Emission Allowances and Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo) In regulated jurisdictions, the Registrants record emission allowances and renewable energy credits (RECs) at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances and RECs at the lower of cost or market. The Registrants follow the inventory model for these allowances and RECs. Allowances and RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances and RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances and RECs are reported in the Operating Activities section of the statements of cash flows. Allowances are consumed in the production of energy, and RECs are consumed to meet applicable state renewable portfolio standards and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenues on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances and RECs affects the determination of deferred fuel or deferred emission allowance and REC costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheet. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo) The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and 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 benefits and 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. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.
Deferred Fuel Costs	Deferred Fuel Costs (Applies to all Registrants except AEP Texas and AEPTCo) The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. In Ohio, changes in fuel costs and purchased power costs, incurred from 2009 through 2011, continue to be recovered in rider rates that will terminate in December 2018. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. In accordance with the accounting guidance for “Regulated Operations - Revenue Recognition”, the Registrants recognize revenue and expense related to the rate true-ups immediately following the annual FERC filings. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo) The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 .
Levelization of Nuclear Refueling Outage Costs	Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M) In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The Registrants revalued deferred tax assets and liabilities at the new federal corporate income tax rate of 21% in December 2017. See Note 12 for additional information related to Tax Reform. When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes (Applies to all Registrants except AEPTCo) As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. Management also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Pension and Other Postretirement Plans	Pension and OPEB Plans (Applies to all Registrants except AEPTCo) 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. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans. 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo) AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 49 % Fixed Income 49 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (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. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Comprehensive Income (Loss)	Comprehensive Income (Loss) (Applies to all Registrants except AEPTCo) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2017 , AEP had performance units and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, performance units awarded prior to 2017 are settled in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vest to executive officers, which are settled in cash. All performance units and restricted stock units awarded after January 1, 2017 will be settled in AEP common shares. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance units granted to employees under the 2015 LTIP. AEP career shares are equal in value to shares of AEP common stock and become payable to executives after their service ends. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. In 2017 the SORP was changed to provide all future AEP career share payments to be made in AEP common stock, rather than cash. Performance units awarded after January 1, 2017 are classified as temporary equity in the mezzanine section of the balance sheet. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units become payable in cash to directors after their service ends. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2017 , 2016 and 2015 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur. For the years ended December 31, 2017 , 2016 and 2015 , compensation cost is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units. Compensation cost may also be capitalized. See Note 15 for additional information.
Equity Method Investments	Equity Investment of Unconsolidated Affiliates (Applies to AEP and SWEPCo) AEP includes equity in earnings from equity method investments in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. SWEPCo includes equity in earnings from an equity method investment in Equity Earnings (Loss) of Unconsolidated Subsidiary on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. AEP has two significant equity method investments, ETT and DHLC. ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50% membership interest in ETT, AEP Transmission Holdco holds a 49.5% membership interest in ETT and AEP Transmission Partner holds the remaining 0.5% membership interest in ETT. As a result, AEP, through its wholly-owned subsidiaries, holds a 50% membership interest in ETT. As of December 31, 2017 , AEP’s investment in ETT was $664 million which is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP’s equity earnings associated with ETT were $82 million for the year ended December 31, 2017 . See “Non-Consolidated Significant Variable Interest” section of Note 17 for more information about DHLC.
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.

Benefit Plans (Policies)

Benefit Plans (Policies)	12 Months Ended
	Dec. 31, 2017
Pension and Other Postretirement Plans	Pension and OPEB Plans (Applies to all Registrants except AEPTCo) 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. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans. 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	12 Months Ended
	Dec. 31, 2017
Derivatives and Hedging	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP 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 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 into 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 Investors Service Inc., S&P Global Inc. 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) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit 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. 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. 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.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2017
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
	Dec. 31, 2017
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The Registrants revalued deferred tax assets and liabilities at the new federal corporate income tax rate of 21% in December 2017. See Note 12 for additional information related to Tax Reform. When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Leases (Policies)

Leases (Policies)	12 Months Ended
	Dec. 31, 2017
Lessee, Leases [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.

Stock-Based Compensation (Polic

Stock-Based Compensation (Policies)	12 Months Ended
	Dec. 31, 2017
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2017 , AEP had performance units and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, performance units awarded prior to 2017 are settled in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vest to executive officers, which are settled in cash. All performance units and restricted stock units awarded after January 1, 2017 will be settled in AEP common shares. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance units granted to employees under the 2015 LTIP. AEP career shares are equal in value to shares of AEP common stock and become payable to executives after their service ends. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. In 2017 the SORP was changed to provide all future AEP career share payments to be made in AEP common stock, rather than cash. Performance units awarded after January 1, 2017 are classified as temporary equity in the mezzanine section of the balance sheet. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units become payable in cash to directors after their service ends. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2017 , 2016 and 2015 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur. For the years ended December 31, 2017 , 2016 and 2015 , compensation cost is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units. Compensation cost may also be capitalized. See Note 15 for additional information.
Stock Based Compensation [Member]
Stock-based Compensation	Awards under AEP’s long-term incentive plan may be granted to employees and directors. The Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2017 , 9,011,946 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award that settles in AEP stock, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. Cash settled awards do not reduce the aggregate amount authorized under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units are adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.35 years . Under the 2015 LTIP and Prior Plan, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. In 2017, AEP used a combination of all three to fulfill share commitments. AEP’s current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset AEP’s tax withholding obligation.
Performance Units [Member]
Stock-based Compensation	Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all performance periods were dependent on two equally-weighted performance measures: (a) three -year total shareholder return measured relative to a peer group of similar companies (b) three -year cumulative earnings per share measured relative to a target approved by the HR Committee. Performance units granted prior to 2017 are settled in cash rather than AEP common stock and do not reduce the aggregate share authorization. These performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance units granted in 2017 will be settled in AEP common stock and will reduce the aggregate share authorization. In all cases the number of performance units held at the end of the three year performance period is multiplied by the performance score for such period to determine the actual number of performance units realized. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee). Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, a portion or all of their performance units are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock. AEP career shares are settled in AEP common stock after the participant’s termination of employment. AEP career shares are recorded in Paid in Capital on the balance sheet. Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units. Management records compensation cost for performance units over an approximately three-year vesting period. The liability for the pre 2017 performance units is recorded in Employee Benefits and Pension Obligations on the balance sheet and is adjusted for changes in value. Performance units settled in shares are recorded as mezzanine equity on the balance sheet and compensation cost is calculated at fair value using two metrics. Half is based on the total shareholder return measure, which is determined based on a third party Monte Carlo valuation. That metric doesn’t change over the three year vesting period. The other half is based on a three year cumulative earnings per share metric which is adjusted quarterly for changes in performance relative to a target approved by the HR Committee. Monte Carlo Valuation AEP engaged a third party for a Monte Carlo valuation to calculate half of the fair value for the performance units awarded during 2017. The valuation used a lattice model and the expected volatility assumption used was the historical volatilities for AEP and the members of their peer group over the last 2.86 years (period from award date to vesting date). The range of expected volatilities was 15.65% to 27.19% with an average expected volatility of 19.07% . The dividend rates used were 0% which is the equivalent to reinvesting dividends. The risk-free rate used was 1.44% , which was interpolated between the two year rate of 1.21% and three year rate of 1.48% since 2.86 years was the vesting period from award date to vesting date.
Restricted Shares and Restricted Stock Units [Member]
Stock-based Compensation	The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting, except that RSUs granted prior to 2017 that vest to AEP’s executive officers are settled in cash. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. For RSUs settled in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs settled in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting is determined by multiplying the number of RSUs vested by the 20 -day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 72 months from the grant date.
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Stock-based Compensation	AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to Non-Employee Directors are fully vested upon grant date. Stock units are settled in cash upon termination of board service or up to 10 years later if the participant so elects. Cash settlements for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investments that are similar to the investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20 -day average closing price of AEP common stock on the valuation date.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	12 Months Ended
	Dec. 31, 2017
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

Property, Plant and Equipment (

Property, Plant and Equipment (Policies)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment	SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

Organization and Summary of S38

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Reconciliation of Cash, Cash Equivalents and Restricted Cash [Table Text Block]	December 31, 2017 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 214.6 $ 2.0 $ 2.9 $ 3.1 Restricted Cash 198.0 155.2 16.3 26.6 Total Cash, Cash Equivalents and Restricted Cash $ 412.6 $ 157.2 $ 19.2 $ 29.7 December 31, 2016 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 210.5 $ 0.6 $ 2.7 $ 3.1 Restricted Cash 193.0 146.3 15.8 27.2 Total Cash, Cash Equivalents and Restricted Cash $ 403.5 $ 146.9 $ 18.5 $ 30.3
Significant Customers	Significant Customers of AEP Texas: Centrica, Just Energy and Reliant Energy 2017 (a) 2016 2015 Percentage of Total Revenues 35 % 46 % 53 % Percentage of Accounts Receivable – Customers 31 % 42 % 43 % (a) Just Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer. Significant Customers of AEPTCo: AEP Subsidiaries 2017 2016 2015 Percentage of Total Revenues 80 % 77 % 73 % Percentage of Total Accounts Receivable 82 % 86 % 77 %
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 49 % Fixed Income 49 % Cash and Cash Equivalents 2 %
Basic and Diluted EPS Calculations	Years Ended December 31, 2017 2016 2015 (in millions, except per share data) $/share $/share $/share Income from Continuing Operations $ 1,928.9 $ 620.5 $ 1,768.6 Less: Net Income Attributable to Noncontrolling Interests 16.3 7.1 5.2 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,912.6 $ 613.4 $ 1,763.4 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.89 491.5 $ 1.25 490.3 $ 3.59 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 (0.01 ) 0.2 — 0.3 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 3.88 491.7 $ 1.25 490.6 $ 3.59
Supplementary Information	Years Ended December 31, Cash Flow Information 2017 2016 2015 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 858.3 $ 848.5 $ 857.2 Income Taxes (1.1 ) 29.5 120.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 60.7 86.1 150.2 Construction Expenditures Included in Current Liabilities as of December 31, 1,330.8 858.0 741.4 Construction Expenditures Included in Noncurrent Liabilities as of December 31, 71.8 — 51.6 Construction Expenditures Included in Noncurrent Assets as of December 31, — — 10.5 Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, — 2.1 37.9 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.6 0.7 2.2 2017 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,709.1 $ 221.1 $ 97.1 $ 407.6 $ 203.1 $ 200.9 $ 131.4 $ 217.2 Amortization of Certain Securitized Assets 275.9 231.4 — — — 44.4 — — Amortization of Regulatory Assets and Liabilities 12.2 (2.4 ) — 0.3 7.8 (19.4 ) (1.0 ) 0.2 Total Depreciation and Amortization $ 1,997.2 $ 450.1 $ 97.1 $ 407.9 $ 210.9 $ 225.9 $ 130.4 $ 217.4 2016 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 204.0 $ 65.9 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 210.3 — — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 (0.4 ) — 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 413.9 $ 65.9 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 193.3 $ 42.4 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 275.5 — — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 0.1 — 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 468.9 $ 42.4 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0

Comprehensive Income (Tables)

Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2017
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (20.4 ) 1.6 3.5 — 86.5 71.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — — (5.6 ) Purchased Electricity for Resale 28.8 — — — — 28.8 Interest Expense — 1.5 — — — 1.5 Amortization of Prior Service Cost (Credit) — — — (19.6 ) — (19.6 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 23.2 1.5 — 1.7 — 26.4 Income Tax (Expense) Credit 8.1 0.4 — 0.6 — 9.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 15.1 1.1 — 1.1 — 17.3 Net Current Period Other Comprehensive Income (Loss) (5.3 ) 2.7 3.5 1.1 86.5 88.5 Balance in AOCI as of December 31, 2017 $ (28.4 ) $ (13.0 ) $ 11.9 $ 141.6 $ (179.9 ) $ (67.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (5.4 ) $ 4.2 $ (13.7 ) $ (14.9 ) Change in Fair Value Recognized in AOCI — — 1.1 1.1 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains)/Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 0.4 — 1.7 Income Tax (Expense) Credit 0.4 0.1 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 0.3 — 1.2 Net Current Period Other Comprehensive Income (Loss) 0.9 0.3 1.1 2.3 Balance in AOCI as of December 31, 2017 $ (4.5 ) $ 4.5 $ (12.6 ) $ (12.6 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (6.5 ) $ 3.9 $ (14.6 ) $ (17.2 ) Change in Fair Value Recognized in AOCI (0.1 ) — 0.9 0.8 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.8 — — 1.8 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains)/Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 0.4 — 2.2 Income Tax (Expense) Credit 0.6 0.1 — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 0.3 — 1.5 Net Current Period Other Comprehensive Income (Loss) 1.1 0.3 0.9 2.3 Balance in AOCI as of December 31, 2016 $ (5.4 ) $ 4.2 $ (13.7 ) $ (14.9 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ (7.7 ) $ 3.6 $ (14.8 ) $ (18.9 ) Change in Fair Value Recognized in AOCI (0.1 ) — 0.2 0.1 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.9 — — 1.9 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains)/Losses — 0.6 — 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.9 0.5 — 2.4 Income Tax (Expense) Credit 0.6 0.2 — 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 0.3 — 1.6 Net Current Period Other Comprehensive Income (Loss) 1.2 0.3 0.2 1.7 Balance in AOCI as of December 31, 2015 $ (6.5 ) $ 3.9 $ (14.6 ) $ (17.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — 11.6 11.6 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — (5.2 ) — (5.2 ) Amortization of Actuarial (Gains)/Losses — 3.4 — 3.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) (1.8 ) — (2.9 ) Income Tax (Expense) Credit (0.4 ) (0.6 ) — (1.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.7 ) (1.2 ) — (1.9 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) (1.2 ) 11.6 9.7 Balance in AOCI as of December 31, 2017 $ 2.2 $ 14.8 $ (15.7 ) $ 1.3 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — 2.8 2.8 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 — — 2.0 Income Tax (Expense) Credit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) 1.3 — 2.8 4.1 Balance in AOCI as of December 31, 2017 $ (10.7 ) $ 5.1 $ (6.5 ) $ (12.1 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 — — 2.0 Income Tax (Expense) Credit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 — — 1.7 Income Tax (Expense) Credit 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Cash Flow Hedge - 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 (1.7 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.7 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.1 ) Net Current Period Other Comprehensive Income (Loss) (1.1 ) Balance in AOCI as of December 31, 2017 $ 1.9 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedge - 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 (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.9 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) Balance in AOCI as of December 31, 2016 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedge - Interest Rate (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) Income Tax (Expense) Credit (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) Balance in AOCI as of December 31, 2015 $ 4.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Cash Flow Hedge - 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2017 $ 2.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedge - 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 (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2016 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedge - Interest Rate (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2015 $ 4.2 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2017 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — 4.7 4.7 Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.2 — — 2.2 Amortization of Prior Service Cost (Credit) — (2.0 ) — (2.0 ) Amortization of Actuarial (Gains)/Losses — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.2 (1.1 ) — 1.1 Income Tax (Expense) Credit 0.8 (0.4 ) — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.4 (0.7 ) — 0.7 Net Current Period Other Comprehensive Income (Loss) 1.4 (0.7 ) 4.7 5.4 Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 1.2 $ 0.8 $ (4.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Pension and OPEB Amortization Changes in Cash Flow Hedge - of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 )

Effects of Regulation (Tables)

Effects of Regulation (Tables)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets	I&M December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 15.0 $ 13.0 1 year Under-recovered Fuel Costs - does not earn a return — 13.1 Total Current Regulatory Assets $ 15.0 $ 26.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 15.9 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 14.7 8.1 Rockport Plant Dry Sorbent Injection System - Indiana 10.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 2.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval 79.3 64.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 245.3 252.8 27 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.0 6.3 21 years Other Regulatory Assets Approved for Recovery 1.0 2.5 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 77.8 141.9 12 years Cook Plant Nuclear Refueling Outage Levelization 66.7 75.2 2 years Deferred PJM Fees 48.0 — 2 years Postemployment Benefits 9.7 11.4 5 years Unamortized Loss on Reacquired Debt 9.5 10.7 15 years Off-system Sales Margin Sharing - Indiana 9.0 24.3 2 years Medicare Subsidy 7.1 8.2 7 years Income Taxes, Net — 302.6 Other Regulatory Assets Approved for Recovery 20.0 16.0 various Total Regulatory Assets Approved for Recovery 500.1 851.9 Total Noncurrent Regulatory Assets $ 579.4 $ 916.6 AEP December 31, Remaining Recovery Period 2017 2016 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 203.1 $ 61.4 1 year Under-recovered Fuel Costs - does not earn a return 89.4 95.2 1 year Total Current Regulatory Assets $ 292.5 $ 156.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 159.9 Ohio Capacity Deferral — 96.7 Storm-Related Costs — 25.1 Other Regulatory Assets Pending Final Regulatory Approval 9.6 10.4 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 128.0 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 39.7 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects — 24.1 Cook Plant Turbine 15.9 12.8 Other Regulatory Assets Pending Final Regulatory Approval 42.2 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) 322.0 450.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (c) 682.6 550.6 27 years Ohio Capacity Deferral 172.6 201.9 2 years Basic Transmission Cost Rider 90.8 19.9 2 years Meter Replacement Costs 83.7 99.9 10 years Ohio Distribution Decoupling 61.7 41.8 2 years Storm-Related Costs 39.3 15.3 4 years Plant Retirement Costs - Asset Retirement Obligation Costs 34.3 18.3 23 years Advanced Metering System 33.5 20.9 3 years Environmental Control Projects 28.1 — 23 years Mitchell Plant Transfer 17.8 18.5 23 years West Virginia Delayed Customer Billing 8.4 19.5 1 year Ohio Phase-In Recovery Rider — 218.9 Other Regulatory Assets Approved for Recovery 41.0 55.4 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,196.3 1,516.2 12 years Unrealized Loss on Forward Commitments 139.3 119.1 15 years Unamortized Loss on Reacquired Debt 129.9 137.8 28 years Cook Plant Nuclear Refueling Outage Levelization 66.7 75.2 2 years Deferred PJM Fees 48.0 — 2 years Storm-Related Costs 44.2 58.7 6 years Peak Demand Reduction/Energy Efficiency 40.1 49.9 3 years Postemployment Benefits 39.1 39.1 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 48.9 23 years Vegetation Management 33.5 31.4 7 years Virginia Transmission Rate Adjustment Clause 32.6 38.7 2 years Medicare Subsidy 32.5 37.2 7 years Off-system Sales Margin Sharing - Indiana 9.0 24.3 2 years United Mine Workers of America Pension Withdrawal 0.5 20.2 5 years Income Taxes, Net — 1,575.0 OVEC Purchased Power — 22.1 Other Regulatory Assets Approved for Recovery 122.9 100.7 various Total Regulatory Assets Approved for Recovery 3,265.6 5,175.4 Total Noncurrent Regulatory Assets $ 3,587.6 $ 5,625.5 (a) As of December 31, 2017, AEP Texas has deferred $100 million related to Hurricane Harvey and is currently exploring recovery options. (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. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. (c) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of December 31, 2017 the unrecovered plant balance related to Northeastern Plant, Unit 3 was $57 million . APCo December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 21.4 $ 6.2 1 year Under-recovered Fuel Costs - does not earn a return 67.4 62.2 1 year Total Current Regulatory Assets $ 88.8 $ 68.4 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: 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 39.7 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) 49.4 39.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 86.3 85.4 26 years West Virginia Delayed Customer Billing 7.8 18.1 1 year Other Regulatory Assets Approved for Recovery 3.9 6.8 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 168.8 221.4 12 years Unamortized Loss on Reacquired Debt 93.2 97.2 28 years Vegetation Management Program - West Virginia 33.5 31.4 7 years Virginia Transmission Rate Adjustment Clause 32.6 38.7 2 years Storm-Related Costs - West Virginia 32.2 47.8 3 years Postemployment Benefits 18.8 17.4 5 years Peak Demand Reduction/Energy Efficiency 18.1 19.2 3 years Virginia Generation Rate Adjustment Clause 7.3 6.5 2 years Income Taxes, Net — 463.5 Other Regulatory Assets Approved for Recovery 22.0 28.4 various Total Regulatory Assets Approved for Recovery 524.5 1,081.8 Total Noncurrent Regulatory Assets $ 573.9 $ 1,121.1 (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. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. AEPTCo December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Noncurrent Regulatory Assets Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Income Taxes, Net $ — $ 106.1 Under-Recovered SPP Revenues — 1.6 Regulatory Assets Currently Not Earning a Return Under-Recovered OATT Costs 11.7 4.6 1 year Total Regulatory Assets Approved for Recovery 11.7 112.3 Total Noncurrent Regulatory Assets $ 11.7 $ 112.3 OPCo December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return (a) $ 115.9 $ — 1 year Total Current Regulatory Assets $ 115.9 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 (b) Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval — 100.8 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 172.6 201.9 2 years Basic Transmission Cost Rider 90.8 19.9 2 years Distribution Decoupling 61.7 41.8 2 years Phase-In Recovery Rider — 218.9 Other Regulatory Assets Approved for Recovery 1.7 4.2 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 170.6 225.2 12 years Unrealized Loss on Forward Commitments 131.8 118.6 15 years Unamortized Loss on Reacquired Debt 7.8 9.1 21 years Income Taxes, Net — 126.4 OVEC Purchased Power — 22.1 Other Regulatory Assets Approved for Recovery 15.8 18.6 various Total Regulatory Assets Approved for Recovery 652.8 1,006.7 Total Noncurrent Regulatory Assets $ 652.8 $ 1,107.5 (a) December 31, 2017 balance includes Phase-In Recovery Rider. (b) Capacity Deferral related to 2016 Global Settlement was approved for recovery effective March 2017. SWEPCo December 31, Remaining Recovery Period 2017 2016 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 14.1 $ 8.4 1 year Total Current Regulatory Assets $ 14.1 $ 8.4 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.3 1.0 Asset Retirement Obligation - Arkansas, Louisiana 4.0 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Controls Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.5 1.9 Total Regulatory Assets Pending Final Regulatory Approval 64.9 95.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 7.2 1.3 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 101.0 119.8 12 years Plant Retirement Costs - Unrecovered Plant 17.6 — 24 years Environmental Controls Projects 15.3 — 15 years Unamortized Loss on Reacquired Debt 4.7 5.4 26 years Medicare Subsidy 3.7 4.3 7 years Income Taxes, Net — 314.2 Other Regulatory Assets Approved for Recovery 6.2 10.3 various Total Regulatory Assets Approved for Recovery 155.7 455.3 Total Noncurrent Regulatory Assets $ 220.6 $ 551.2 AEP Texas December 31, Remaining Recovery Period Regulatory Assets: 2017 2016 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm-Related Costs $ — $ 25.1 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 123.3 — Rate Case Expense 0.1 0.1 Total Regulatory Assets Pending Final Regulatory Approval 123.4 25.2 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 44.9 49.8 10 years Advanced Metering System 33.5 21.3 3 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 151.2 188.2 12 years Transmission Cost Recovery Factor 9.5 5.3 1 year Unamortized Loss on Reacquired Debt 7.7 7.3 20 years Income Taxes, Net — 40.3 Other Regulatory Assets Approved for Recovery 8.5 9.8 various Total Regulatory Assets Approved for Recovery 255.3 322.0 Total Noncurrent Regulatory Assets $ 378.7 $ 347.2 (a) As of December 31, 2017, AEP Texas has deferred $100 million related to Hurricane Harvey and is currently exploring recovery options. PSO December 31, Remaining Recovery Period 2017 2016 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 36.7 $ 33.8 1 year Total Current Regulatory Assets $ 36.7 $ 33.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ — $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval — 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 3.2 20.0 Environmental Control Projects — 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Total Regulatory Assets Pending Final Regulatory Approval 3.3 118.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) 138.5 — 23 years Storm-Related Costs 39.0 10.8 4 years Meter Replacement Costs 38.8 50.1 7 years Environmental Control Projects 28.1 — 23 years Red Rock Generating Facility 8.8 9.1 39 years Other Regulatory Assets Approved for Recovery 0.5 — various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 72.7 98.1 12 years SPP Base Plan Fees 16.3 10.7 2 years Peak Demand Reduction/Energy Efficiency 13.0 10.3 2 years Unamortized Loss on Reacquired Debt 5.0 5.8 15 years Deferred System Reliability Rider Expenses — 12.5 Income Taxes, Net — 9.3 Other Regulatory Assets Approved for Recovery 4.1 5.4 various Total Regulatory Assets Approved for Recovery 364.8 222.1 Total Noncurrent Regulatory Assets $ 368.1 $ 340.2 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of December 31, 2017 the unrecovered plant balance related to Northeastern Plant, Unit 3 was $57 million .
Regulatory Liabilities	SWEPCo December 31, Remaining Refund Period 2017 2016 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.7 $ 3.8 1 year Total Current Regulatory Liabilities $ 8.7 $ 3.8 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 455.9 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 455.9 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 424.5 409.7 (b) Refundable Construction Financing Costs - Louisiana — 16.2 Other Regulatory Liabilities Approved for Payment 2.6 3.9 various Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 5.9 7.3 14 years Other Regulatory Liabilities Approved for Payment 7.5 1.8 various Total Regulatory Liabilities Approved for Payment 440.5 438.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 896.4 $ 438.9 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. PSO December 31, Remaining Refund Period 2017 2016 Regulatory Liabilities: (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 531.7 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 531.7 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 268.8 279.3 (b) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 50.7 48.0 41 years Advanced Metering Costs 0.6 11.5 1 year Other Regulatory Liabilities Approved for Payment 1.7 0.9 various Total Regulatory Liabilities Approved for Payment 321.8 339.7 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 853.5 $ 339.7 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. AEP Texas December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 642.9 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 642.9 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 599.2 581.7 (b) Advanced Metering Infrastructure Surcharge 12.7 17.0 3 years Excess Earnings 6.8 7.3 14 years Regulatory Liabilities Currently Not Paying a Return Transition Charges 46.0 40.5 10 years Deferred Investment Tax Credits 12.3 13.9 45 years Other Regulatory Liabilities Approved for Payment 0.6 0.4 various Total Regulatory Liabilities Approved for Payment 677.6 660.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,320.5 $ 660.8 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 820.3 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 820.3 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 615.8 616.9 (b) Deferred Investment Tax Credits 0.9 0.9 41 years Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 9.5 1.3 7 years Consumer Rate Relief - West Virginia 6.5 5.1 1 year Other Regulatory Liabilities Approved for Payment 1.9 3.6 various Total Regulatory Liabilities Approved for Payment 634.6 627.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,454.9 $ 627.8 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. OPCo December 31, Remaining Refund Period 2017 2016 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ — $ 4.2 Total Current Regulatory Liabilities $ — $ 4.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 604.2 $ — Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 604.4 0.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 428.8 432.4 (b) Other Regulatory Liabilities Approved for Payment 1.4 0.3 various Regulatory Liabilities Currently Not Paying a Return Enhanced Service Reliability Plan 30.6 21.7 2 years Peak Demand Reduction/Energy Efficiency 23.6 29.0 2 years Smart Grid Costs 1.4 11.9 1 year Other Regulatory Liabilities Approved for Payment 10.0 10.7 various Total Regulatory Liabilities Approved for Payment 495.8 506.0 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,100.2 $ 506.2 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2017 2016 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 36.7 $ 33.8 1 year Total Current Regulatory Assets $ 36.7 $ 33.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ — $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval — 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 3.2 20.0 Environmental Control Projects — 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Total Regulatory Assets Pending Final Regulatory Approval 3.3 118.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) 138.5 — 23 years Storm-Related Costs 39.0 10.8 4 years Meter Replacement Costs 38.8 50.1 7 years Environmental Control Projects 28.1 — 23 years Red Rock Generating Facility 8.8 9.1 39 years Other Regulatory Assets Approved for Recovery 0.5 — various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 72.7 98.1 12 years SPP Base Plan Fees 16.3 10.7 2 years Peak Demand Reduction/Energy Efficiency 13.0 10.3 2 years Unamortized Loss on Reacquired Debt 5.0 5.8 15 years Deferred System Reliability Rider Expenses — 12.5 Income Taxes, Net — 9.3 Other Regulatory Assets Approved for Recovery 4.1 5.4 various Total Regulatory Assets Approved for Recovery 364.8 222.1 Total Noncurrent Regulatory Assets $ 368.1 $ 340.2 AEP December 31, Remaining 2017 2016 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 8.7 $ 3.8 1 year Over-recovered Fuel Costs - does not pay a return 3.2 4.2 1 year Total Current Regulatory Liabilities $ 11.9 $ 8.0 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 4,412.8 $ — Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.8 Total Regulatory Liabilities Pending Final Regulatory Determination 4,413.0 0.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (b) 2,637.1 2,627.5 (c) Advanced Metering Infrastructure Surcharge 12.7 17.0 3 years Deferred Investment Tax Credits 10.6 12.6 41 years Excess Earnings 9.4 10.0 36 years Louisiana Refundable Construction Financing Costs — 16.2 Other Regulatory Liabilities Approved for Payment 1.3 1.6 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 945.0 731.2 (d) Deferred Investment Tax Credits 191.2 132.9 45 years Transition Charges 46.0 40.5 10 years Spent Nuclear Fuel 43.2 44.2 (d) Enhanced Service Reliability Plan 30.6 21.7 2 years Peak Demand Reduction/Energy Efficiency 25.6 34.0 2 years Other Regulatory Liabilities Approved for Payment 56.6 61.1 various Total Regulatory Liabilities Approved for Payment 4,009.3 3,750.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,422.3 $ 3,751.3 (a) This balance primarily represents regulatory liabilities for excess accumulated deferred income taxes (Excess ADIT) as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) As of December 31, 2017, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (c) Relieved as removal costs are incurred. (d) Relieved when plant is decommissioned. AEPTCo December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Noncurrent Regulatory Liabilities Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 427.0 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 427.0 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 66.7 44.0 (b) Total Regulatory Liabilities Approved for Payment 66.7 44.0 Total Noncurrent Regulatory Liabilities $ 493.7 $ 44.0 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2017 2016 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 2.7 $ — 1 year Total Current Regulatory Liabilities $ 2.7 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 472.7 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 472.7 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (b) 202.2 236.5 (c) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 945.0 731.2 (d) Spent Nuclear Fuel 43.2 44.2 (d) Deferred Investment Tax Credits 34.1 38.8 20 years Other Regulatory Liabilities Approved for Payment 11.5 14.8 various Total Regulatory Liabilities Approved for Payment 1,236.0 1,065.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,708.7 $ 1,065.5 (a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information. (b) As of December 31, 2017, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (c) Relieved as removal costs are incurred. (d) Relieved when plant is decommissioned.

Commitments, Guarantees and C41

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 1,067.6 $ 1,019.5 $ 544.9 $ 221.6 $ 2,853.6 Energy and Capacity Purchase Contracts 230.1 456.1 378.0 1,467.3 2,531.5 Total $ 1,297.7 $ 1,475.6 $ 922.9 $ 1,688.9 $ 5,385.1 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 369.1 $ 364.4 $ 165.2 $ 0.9 $ 899.6 Energy and Capacity Purchase Contracts 36.0 72.3 72.9 354.9 536.1 Total $ 405.1 $ 436.7 $ 238.1 $ 355.8 $ 1,435.7 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 236.9 $ 269.4 $ 204.6 $ 166.6 $ 877.5 Energy and Capacity Purchase Contracts 125.4 255.9 259.9 352.4 993.6 Total $ 362.3 $ 525.3 $ 464.5 $ 519.0 $ 1,871.1 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 29.9 $ 59.3 $ 58.4 $ 363.7 $ 511.3 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 45.9 $ 71.7 $ 30.5 $ — $ 148.1 Energy and Capacity Purchase Contracts 91.5 181.5 127.8 236.8 637.6 Total $ 137.4 $ 253.2 $ 158.3 $ 236.8 $ 785.7 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 111.7 $ 85.8 $ 55.4 $ — $ 252.9 Energy and Capacity Purchase Contracts 33.0 67.3 53.4 151.0 304.7 Total $ 144.7 $ 153.1 $ 108.8 $ 151.0 $ 557.6 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 103.5 January 2018 to December 2018 AEP Texas 2.8 January 2018 OPCo 0.6 September 2018

Dispositions, Assets and Liab42

Dispositions, Assets and Liabilities Held for Sale and Impairments (Tables)	12 Months Ended
	Dec. 31, 2017
Dispositions, Assets and Liabilities Held for Sale	Generation & Marketing Segment December 31, 2016 Assets: (in millions) 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 Sheet $ 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 Sheet $ 235.9 Corporate and Other Years Ended December 31, 2015 (in millions) Other Revenues $ 447.1 Other Operation Expense 321.3 Maintenance Expense 21.5 Depreciation and Amortization Expense 26.9 Taxes Other Than Income Taxes 10.6 Total Expenses 380.3 Other Income (Expense) (16.9 ) Pretax Income of Discontinued Operations 49.9 Income Tax Expense 19.4 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) Income from Discontinued Operations of AEPRO 30.4 Gain on Sale of Discontinued Operations 240.1 Income Tax Expense (Benefit) (13.2 ) Gain on Sale of Discontinued Operations, Net of Tax 253.3 Total Income on Discontinued Operations as Presented on the Statement of Income $ 283.7 AEP Texas Years Ended December 31, 2016 2015 (in millions) Revenue $ 18.2 $ 22.4 Other Operation Expense 6.5 6.5 Maintenance Expense 3.4 4.9 Asset Impairment and Other Related Charges 72.7 — Depreciation and Amortization Expense 9.8 11.5 Taxes Other Than Income Taxes 1.3 1.3 Total Expenses 93.7 24.2 Other Income (Expense) (0.8 ) (1.3 ) Pretax Income of Discontinued Operations (76.3 ) (3.1 ) Income Tax Expense (27.5 ) (1.7 ) Total Income on Discontinued Operations as Presented on the Statements of Income $ (48.8 ) $ (1.4 )
Impaired Assets	Impaired Assets Book Value Fair Value Impairment (in millions) Merchant Coal-Fired Generation Assets $ 2,139.4 $ — $ 2,139.4 Trent and Desert Sky Wind Farms 118.7 46.0 72.7 Coal Reserves (a) 56.6 3.8 52.8 Total $ 2,314.7 $ 49.8 $ 2,264.9 (a) Includes the $11 million book value of I&M’s Price River Coal Reserves which were fully impaired. This $11 million impairment is reflected in the Vertically Integrated Utilities Segment.

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Health Care Trend Rates	December 31, Health Care Trend Rates 2017 2016 Initial 6.50 % 7.00 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 2.5 $ 0.1 $ 0.5 $ 0.2 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.0 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 45.4 $ 2.6 $ 10.8 $ 3.7 $ 3.5 $ 1.7 $ 1.9 1% Decrease (39.6 ) (2.4 ) (9.1 ) (3.4 ) (3.2 ) (1.5 ) (1.8 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	AEP Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Service Cost 96.5 85.8 11.2 10.2 Interest Cost 203.1 211.6 59.3 60.9 Actuarial (Gain) Loss 182.4 142.7 (97.5 ) 17.3 Benefit Payments (352.0 ) (347.2 ) (128.6 ) (130.2 ) Participant Contributions — — 39.5 37.8 Medicare Subsidy — — 0.7 0.8 Benefit Obligation as of December 31, $ 5,215.8 $ 5,085.8 $ 1,332.0 $ 1,447.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Actual Gain on Plan Assets 600.0 315.5 271.6 56.0 Company Contributions 98.8 91.4 4.1 4.9 Participant Contributions — — 39.5 37.8 Benefit Payments (352.0 ) (347.2 ) (128.6 ) (130.2 ) Fair Value of Plan Assets as of December 31, $ 5,174.1 $ 4,827.3 $ 1,732.5 $ 1,545.9 Funded (Underfunded) Status as of December 31, $ (41.7 ) $ (258.5 ) $ 400.5 $ 98.5 AEP Texas Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 421.7 $ 420.3 $ 120.4 $ 122.0 Transfer of CSW Energy, Inc. Benefit Obligation — (2.8 ) — (0.4 ) Service Cost 8.6 7.5 0.9 0.7 Interest Cost 17.1 17.8 4.9 5.1 Actuarial (Gain) Loss 25.6 11.1 (11.9 ) 0.8 Benefit Payments (31.7 ) (32.2 ) (10.8 ) (11.4 ) Participant Contributions — — 3.6 3.5 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 441.3 $ 421.7 $ 107.1 $ 120.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 416.6 $ 415.4 $ 134.1 $ 138.6 Transfer of CSW Energy, Inc. Plan Assets — (2.5 ) — (0.4 ) Actual Gain on Plan Assets 61.8 27.4 20.4 3.8 Company Contributions 9.2 8.5 — — Participant Contributions — — 3.6 3.5 Benefit Payments (31.7 ) (32.2 ) (10.8 ) (11.4 ) Fair Value of Plan Assets as of December 31, $ 455.9 $ 416.6 $ 147.3 $ 134.1 Funded (Underfunded) Status as of December 31, $ 14.6 $ (5.1 ) $ 40.2 $ 13.7 APCo Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Service Cost 9.4 8.1 1.1 1.0 Interest Cost 25.7 27.2 10.6 10.8 Actuarial (Gain) Loss 15.7 9.2 (13.4 ) (0.2 ) Benefit Payments (39.8 ) (43.9 ) (24.3 ) (24.8 ) Participant Contributions — — 6.7 6.4 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 665.0 $ 654.0 $ 236.5 $ 255.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Actual Gain on Plan Assets 74.9 38.3 41.6 5.9 Company Contributions 10.2 8.8 2.5 2.7 Participant Contributions — — 6.7 6.4 Benefit Payments (39.8 ) (43.9 ) (24.3 ) (24.8 ) Fair Value of Plan Assets as of December 31, $ 651.7 $ 606.4 $ 273.4 $ 246.9 Funded (Underfunded) Status as of December 31, $ (13.3 ) $ (47.6 ) $ 36.9 $ (8.7 ) I&M Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Service Cost 14.0 12.2 1.6 1.5 Interest Cost 24.3 25.3 6.9 7.0 Actuarial (Gain) Loss 10.8 20.1 (12.0 ) 3.8 Benefit Payments (36.4 ) (37.5 ) (15.6 ) (15.7 ) Participant Contributions — — 4.9 4.6 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 624.3 $ 611.6 $ 153.5 $ 167.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Actual Gain on Plan Assets 74.0 40.6 35.2 8.7 Company Contributions 13.0 13.0 — — Participant Contributions — — 4.9 4.6 Benefit Payments (36.4 ) (37.5 ) (15.6 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 636.7 $ 586.1 $ 211.1 $ 186.6 Funded (Underfunded) Status as of December 31, $ 12.4 $ (25.5 ) $ 57.6 $ 19.0 OPCo Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Service Cost 7.5 6.5 0.9 0.8 Interest Cost 19.4 20.6 6.7 7.0 Actuarial (Gain) Loss 13.1 4.7 (16.6 ) (1.0 ) Benefit Payments (31.8 ) (36.4 ) (15.5 ) (16.2 ) Participant Contributions — — 4.7 4.7 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 501.1 $ 492.9 $ 144.3 $ 164.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Actual Gain on Plan Assets 58.9 30.9 26.7 2.5 Company Contributions 8.2 7.2 — — Participant Contributions — — 4.7 4.7 Benefit Payments (31.8 ) (36.4 ) (15.5 ) (16.2 ) Fair Value of Plan Assets as of December 31, $ 509.1 $ 473.8 $ 198.5 $ 182.6 Funded (Underfunded) Status as of December 31, $ 8.0 $ (19.1 ) $ 54.2 $ 18.6 PSO Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Service Cost 6.4 6.2 0.7 0.6 Interest Cost 10.7 11.2 3.2 3.3 Actuarial (Gain) Loss 10.1 3.1 (7.5 ) 1.0 Benefit Payments (17.3 ) (19.2 ) (6.9 ) (7.2 ) Participant Contributions — — 2.3 2.2 Benefit Obligation as of December 31, $ 276.6 $ 266.7 $ 69.4 $ 77.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Actual Gain on Plan Assets 33.6 17.3 13.7 3.1 Company Contributions 5.5 5.8 — — Participant Contributions — — 2.3 2.2 Benefit Payments (17.3 ) (19.2 ) (6.9 ) (7.2 ) Fair Value of Plan Assets as of December 31, $ 287.8 $ 266.0 $ 95.5 $ 86.4 Funded (Underfunded) Status as of December 31, $ 11.2 $ (0.7 ) $ 26.1 $ 8.8 SWEPCo Pension Plans OPEB 2017 2016 2017 2016 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Service Cost 8.7 8.1 0.9 0.8 Interest Cost 12.3 12.4 3.6 3.6 Actuarial (Gain) Loss 16.3 13.8 (6.2 ) 1.5 Benefit Payments (19.3 ) (20.5 ) (7.4 ) (7.5 ) Participant Contributions — — 2.5 2.4 Benefit Obligation as of December 31, $ 314.6 $ 296.6 $ 80.3 $ 86.9 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Actual Gain on Plan Assets 34.6 18.8 18.5 4.1 Company Contributions 9.1 8.4 — — Participant Contributions — — 2.5 2.4 Benefit Payments (19.3 ) (20.5 ) (7.4 ) (7.5 ) Fair Value of Plan Assets as of December 31, $ 311.7 $ 287.3 $ 110.4 $ 96.8 Funded (Underfunded) Status as of December 31, $ (2.9 ) $ (9.3 ) $ 30.1 $ 9.9
Benefit Amounts Recognized on the Balance Sheets	Pension Plans OPEB December 31, AEP 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 36.3 $ — $ 463.0 $ 154.5 Other Current Liabilities – Accrued Short-term Benefit Liability (6.2 ) (5.9 ) (3.2 ) (3.0 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (71.8 ) (252.6 ) (59.3 ) (53.0 ) Funded (Underfunded) Status $ (41.7 ) $ (258.5 ) $ 400.5 $ 98.5 Pension Plans OPEB December 31, AEP Texas 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 18.6 $ — $ 40.2 $ 13.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.4 ) (0.4 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (3.6 ) (4.7 ) — — Funded (Underfunded) Status $ 14.6 $ (5.1 ) $ 40.2 $ 13.7 Pension Plans OPEB December 31, APCo 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 74.6 $ 25.2 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.5 ) (2.4 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (13.3 ) (47.6 ) (35.2 ) (31.5 ) Funded (Underfunded) Status $ (13.3 ) $ (47.6 ) $ 36.9 $ (8.7 ) Pension Plans OPEB December 31, I&M 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 13.4 $ — $ 57.6 $ 19.0 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.0 ) (25.5 ) — — Funded (Underfunded) Status $ 12.4 $ (25.5 ) $ 57.6 $ 19.0 Pension Plans OPEB December 31, OPCo 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 8.4 $ — $ 54.2 $ 18.6 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (0.4 ) (19.1 ) — — Funded (Underfunded) Status $ 8.0 $ (19.1 ) $ 54.2 $ 18.6 Pension Plans OPEB December 31, PSO 2017 2016 2017 2016 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 13.9 $ 1.6 $ 26.1 $ 8.8 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (2.5 ) (2.1 ) — — Funded (Underfunded) Status $ 11.2 $ (0.7 ) $ 26.1 $ 8.8 Pension Plans OPEB December 31, SWEPCo 2017 2016 2017 2016 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.1 $ 9.9 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.7 ) (9.2 ) — — Funded (Underfunded) Status $ (2.9 ) $ (9.3 ) $ 30.1 $ 9.9
Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 1,354.2 $ 1,569.8 $ 309.9 $ 614.4 Prior Service Cost (Credit) — 1.0 (416.3 ) (485.4 ) Recorded as Regulatory Assets $ 1,271.3 $ 1,415.6 $ (82.4 ) $ 90.4 Deferred Income Taxes 17.4 54.4 (5.0 ) 13.5 Net of Tax AOCI 53.9 100.8 (15.6 ) 25.1 Income Tax Expense (a) 11.6 — (3.4 ) — AEP Texas Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 175.2 $ 193.3 $ 23.9 $ 50.7 Prior Service Credit — — (35.4 ) (41.2 ) Recorded as Regulatory Assets $ 161.4 $ 178.5 $ (10.2 ) $ 9.7 Deferred Income Taxes 2.9 5.2 (0.3 ) (0.1 ) Net of Tax AOCI 8.9 9.6 (0.8 ) (0.1 ) Income Tax Expense (a) 2.0 — (0.2 ) — APCo Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 182.5 $ 216.2 $ 48.0 $ 92.9 Prior Service Cost (Credit) — 0.2 (60.4 ) (70.5 ) Recorded as Regulatory Assets $ 179.9 $ 213.7 $ (11.1 ) $ 7.7 Deferred Income Taxes 0.5 1.0 (0.3 ) 5.1 Net of Tax AOCI 1.7 1.7 (0.8 ) 9.6 Income Tax Expense (a) 0.4 — (0.2 ) — I&M Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 94.9 $ 133.2 $ 42.0 $ 81.3 Prior Service Cost (Credit) — 0.2 (56.9 ) (66.3 ) Recorded as Regulatory Assets $ 91.8 $ 128.2 $ (14.0 ) $ 13.7 Deferred Income Taxes 0.7 1.8 (0.2 ) 0.5 Net of Tax AOCI 2.0 3.4 (0.6 ) 0.8 Income Tax Expense (a) 0.4 — (0.1 ) — OPCo Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 189.6 $ 215.4 $ 22.6 $ 58.2 Prior Service Cost (Credit) — 0.1 (41.6 ) (48.5 ) Recorded as Regulatory Assets $ 189.6 $ 215.5 $ (19.0 ) $ 9.7 PSO Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 78.8 $ 91.0 $ 19.8 $ 37.3 Prior Service Credit — — (25.9 ) (30.2 ) Recorded as Regulatory Assets $ 78.8 $ 91.0 $ (6.1 ) $ 7.1 SWEPCo Pension Plans OPEB December 31, 2017 2016 2017 2016 Components (in millions) Net Actuarial Loss $ 97.4 $ 103.8 $ 24.7 $ 45.4 Prior Service Cost (Credit) — 0.1 (31.4 ) (36.6 ) Recorded as Regulatory Assets $ 97.4 $ 103.9 $ (3.7 ) $ 5.7 Deferred Income Taxes — — (0.6 ) 1.1 Net of Tax AOCI — — (2.0 ) 2.0 Income Tax Expense (a) — — (0.4 ) — (a) Amounts relate to the re-measurement of Deferred Income Taxes as a result of Tax Reform. In accordance with the accounting guidance for “Income Taxes”, re-measurement of Deferred Income Taxes related to AOCI must flow through the statement of income.
Components of Change in Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (132.8 ) $ 107.5 $ (267.8 ) $ 68.4 Amortization of Actuarial Loss (82.8 ) (83.8 ) (36.7 ) (31.4 ) Amortization of Prior Service Credit (Cost) (1.0 ) (2.3 ) 69.1 69.0 Change for the Year Ended December 31, $ (216.6 ) $ 21.4 $ (235.4 ) $ 106.0 AEP Texas Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (11.1 ) $ 7.1 $ (23.6 ) $ 6.4 Amortization of Actuarial Loss (7.0 ) (7.1 ) (3.2 ) (2.8 ) Amortization of Prior Service Credit (Cost) — (0.4 ) 5.8 6.0 Change for the Year Ended December 31, $ (18.1 ) $ (0.4 ) $ (21.0 ) $ 9.6 APCo Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (23.3 ) $ 6.2 $ (38.6 ) $ 11.4 Amortization of Actuarial Loss (10.4 ) (10.8 ) (6.3 ) (5.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.1 ) 10.1 10.1 Change for the Year Ended December 31, $ (33.9 ) $ (4.7 ) $ (34.8 ) $ 16.1 I&M Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (28.6 ) $ 13.2 $ (34.9 ) $ 7.9 Amortization of Actuarial Loss (9.7 ) (10.0 ) (4.4 ) (3.7 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.1 ) 9.4 9.4 Change for the Year Ended December 31, $ (38.5 ) $ 3.1 $ (29.9 ) $ 13.6 OPCo Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (18.0 ) $ 1.5 $ (31.3 ) $ 9.4 Amortization of Actuarial Loss (7.8 ) (8.1 ) (4.3 ) (3.8 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.1 ) 6.9 6.9 Change for the Year Ended December 31, $ (25.9 ) $ (6.7 ) $ (28.7 ) $ 12.5 PSO Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (7.9 ) $ 1.3 $ (15.5 ) $ 3.9 Amortization of Actuarial Loss (4.3 ) (4.4 ) (2.0 ) (1.8 ) Amortization of Prior Service Credit (Cost) — (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (12.2 ) $ (3.4 ) $ (13.2 ) $ 6.4 SWEPCo Pension Plans OPEB 2017 2016 2017 2016 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.5 ) $ 11.5 $ (18.4 ) $ 4.0 Amortization of Actuarial Loss (4.9 ) (4.8 ) (2.3 ) (1.9 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.3 ) 5.2 5.0 Change for the Year Ended December 31, $ (6.5 ) $ 6.4 $ (15.5 ) $ 7.1
Allocated Assets of Investments	Pension Plan OPEB December 31, Company 2017 2016 2017 2016 AEP Texas 8.8 % 8.6 % 8.5 % 8.7 % APCo 12.6 % 12.6 % 15.8 % 16.0 % I&M 12.3 % 12.1 % 12.2 % 12.1 % OPCo 9.8 % 9.8 % 11.5 % 11.8 % PSO 5.6 % 5.5 % 5.5 % 5.6 % SWEPCo 6.0 % 6.0 % 6.4 % 6.3 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,951.3 $ 421.4 $ 648.0 $ 592.4 $ 483.4 $ 256.9 $ 289.4 Nonqualified Pension Plans 73.9 3.8 0.2 0.4 0.1 2.7 2.2 Total as of December 31, 2017 $ 5,025.2 $ 425.2 $ 648.2 $ 592.8 $ 483.5 $ 259.6 $ 291.6 Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 404.7 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 3.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 408.5 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5
Underfunded Accumulated Benefit Obligation	AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 78.0 $ 4.0 $ 0.4 $ 1.0 $ 0.4 $ 2.7 $ 2.2 Accumulated Benefit Obligation $ 73.9 $ 3.8 $ 0.2 $ 0.4 $ 0.1 $ 2.7 $ 2.2 Fair Value of Plan Assets — — — — — — — Underfunded Accumulated Benefit Obligation as of December 31, 2017 $ (73.9 ) $ (3.8 ) $ (0.2 ) $ (0.4 ) $ (0.1 ) $ (2.7 ) $ (2.2 ) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 3.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 3.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 — 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (3.8 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans OPEB (in millions) AEP $ 100.7 $ 4.2 AEP Texas 3.6 — APCo 9.6 2.5 I&M 1.6 — OPCo 1.2 — PSO 0.2 — SWEPCo 2.8 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 333.2 $ 31.0 $ 42.9 $ 35.1 $ 35.1 $ 18.6 $ 20.8 2019 340.1 31.0 43.9 37.2 35.0 19.5 21.6 2020 345.0 33.7 43.5 37.6 35.1 19.8 21.8 2021 356.2 34.7 44.4 38.7 34.3 21.7 23.2 2022 356.8 33.5 44.6 40.4 35.0 21.1 23.3 Years 2023 to 2027, in Total 1,795.4 165.6 221.3 210.8 165.6 104.3 121.5 OPEB Benefit Payments AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 122.8 $ 10.2 $ 23.3 $ 14.9 $ 14.6 $ 6.5 $ 7.1 2019 123.1 10.4 22.8 14.9 14.7 6.6 7.1 2020 124.0 10.5 22.8 15.0 14.6 6.8 7.4 2021 124.6 10.7 22.6 15.2 14.5 6.8 7.6 2022 124.6 10.8 22.3 15.2 14.5 6.8 7.7 Years 2023 to 2027, in Total 616.4 53.7 106.2 74.8 69.6 34.7 40.4 OPEB Medicare Subsidy Receipts AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 0.3 $ — $ 0.2 $ — $ — $ — $ — 2019 0.3 — 0.2 — — — — 2020 0.3 — 0.2 — — — — 2021 0.3 — 0.2 — — — — 2022 0.3 — 0.2 — — — — Years 2023 to 2027, in Total 1.7 — 0.9 — — — —
Components of Net Periodic Benefit Cost	AEP Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 96.5 $ 85.8 $ 93.5 $ 11.2 $ 10.2 $ 12.2 Interest Cost 203.1 211.6 205.3 59.3 60.9 56.8 Expected Return on Plan Assets (284.8 ) (280.3 ) (274.8 ) (101.3 ) (107.0 ) (111.0 ) Amortization of Prior Service Cost (Credit) 1.0 2.3 2.2 (69.1 ) (69.0 ) (69.1 ) Amortization of Net Actuarial Loss 82.8 83.8 107.1 36.7 31.4 18.8 Net Periodic Benefit Cost (Credit) 98.6 103.2 133.3 (63.2 ) (73.5 ) (92.3 ) Capitalized Portion (39.9 ) (37.8 ) (48.4 ) 25.6 26.9 33.5 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 58.7 $ 65.4 $ 84.9 $ (37.6 ) $ (46.6 ) $ (58.8 ) AEP Texas Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 8.6 $ 7.5 $ 7.6 $ 0.9 $ 0.7 $ 0.8 Interest Cost 17.1 17.8 17.2 4.9 5.1 4.8 Expected Return on Plan Assets (25.0 ) (24.5 ) (24.1 ) (8.8 ) (9.3 ) (9.9 ) Amortization of Prior Service Cost (Credit) — 0.4 0.3 (5.8 ) (6.0 ) (5.9 ) Amortization of Net Actuarial Loss 7.0 7.1 9.0 3.2 2.8 1.5 Net Periodic Benefit Cost (Credit) 7.7 8.3 10.0 (5.6 ) (6.7 ) (8.7 ) Capitalized Portion (4.0 ) (3.6 ) (4.7 ) 2.9 3.4 4.1 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 3.7 $ 4.7 $ 5.3 $ (2.7 ) $ (3.3 ) $ (4.6 ) APCo Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 9.4 $ 8.1 $ 8.7 $ 1.1 $ 1.0 $ 1.1 Interest Cost 25.7 27.2 26.7 10.6 10.8 10.3 Expected Return on Plan Assets (35.8 ) (35.3 ) (35.0 ) (16.5 ) (17.3 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.1 0.2 (10.1 ) (10.1 ) (10.0 ) Amortization of Net Actuarial Loss 10.4 10.8 13.9 6.3 5.4 3.6 Net Periodic Benefit Cost (Credit) 9.9 10.9 14.5 (8.6 ) (10.2 ) (13.1 ) Capitalized Portion (4.0 ) (4.1 ) (5.5 ) 3.5 3.9 5.0 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 5.9 $ 6.8 $ 9.0 $ (5.1 ) $ (6.3 ) $ (8.1 ) I&M Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 14.0 $ 12.2 $ 12.9 $ 1.6 $ 1.5 $ 1.6 Interest Cost 24.3 25.3 24.5 6.9 7.0 6.4 Expected Return on Plan Assets (34.6 ) (33.6 ) (32.6 ) (12.2 ) (12.9 ) (13.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.1 0.2 (9.4 ) (9.4 ) (9.4 ) Amortization of Net Actuarial Loss 9.7 10.0 12.6 4.4 3.7 2.0 Net Periodic Benefit Cost (Credit) 13.6 14.0 17.6 (8.7 ) (10.1 ) (12.6 ) Capitalized Portion (5.5 ) (3.3 ) (4.0 ) 3.5 2.4 2.9 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 8.1 $ 10.7 $ 13.6 $ (5.2 ) $ (7.7 ) $ (9.7 ) OPCo Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 7.5 $ 6.5 $ 6.7 $ 0.9 $ 0.8 $ 0.9 Interest Cost 19.4 20.6 20.3 6.7 7.0 6.4 Expected Return on Plan Assets (27.9 ) (27.6 ) (27.5 ) (11.9 ) (13.0 ) (13.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 0.2 (6.9 ) (6.9 ) (7.0 ) Amortization of Net Actuarial Loss 7.8 8.1 10.5 4.3 3.8 2.1 Net Periodic Benefit Cost (Credit) 6.9 7.7 10.2 (6.9 ) (8.3 ) (11.0 ) Capitalized Portion (3.3 ) (3.4 ) (4.8 ) 3.3 3.7 5.2 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 3.6 $ 4.3 $ 5.4 $ (3.6 ) $ (4.6 ) $ (5.8 ) PSO Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 6.4 $ 6.2 $ 6.4 $ 0.7 $ 0.6 $ 0.7 Interest Cost 10.7 11.2 10.9 3.2 3.3 3.0 Expected Return on Plan Assets (15.6 ) (15.5 ) (15.1 ) (5.6 ) (6.1 ) (6.3 ) Amortization of Prior Service Cost (Credit) — 0.3 0.2 (4.3 ) (4.3 ) (4.3 ) Amortization of Net Actuarial Loss 4.3 4.4 5.7 2.0 1.8 1.0 Net Periodic Benefit Cost (Credit) 5.8 6.6 8.1 (4.0 ) (4.7 ) (5.9 ) Capitalized Portion (2.1 ) (2.4 ) (2.8 ) 1.4 1.7 2.0 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 3.7 $ 4.2 $ 5.3 $ (2.6 ) $ (3.0 ) $ (3.9 ) SWEPCo Pension Plans OPEB Years Ended December 31, 2017 2016 2015 2017 2016 2015 (in millions) Service Cost $ 8.7 $ 8.1 $ 8.3 $ 0.9 $ 0.8 $ 0.8 Interest Cost 12.3 12.4 11.8 3.6 3.6 3.4 Expected Return on Plan Assets (17.0 ) (16.4 ) (16.0 ) (6.3 ) (6.8 ) (6.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.3 0.3 (5.2 ) (5.0 ) (5.2 ) Amortization of Net Actuarial Loss 4.9 4.8 6.0 2.3 1.9 1.1 Net Periodic Benefit Cost (Credit) 9.0 9.2 10.4 (4.7 ) (5.5 ) (6.8 ) Capitalized Portion (2.7 ) (2.7 ) (3.2 ) 1.4 1.6 2.1 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 6.3 $ 6.5 $ 7.2 $ (3.3 ) $ (3.9 ) $ (4.7 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP AEP Texas APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 85.5 $ 7.2 $ 10.8 $ 10.1 $ 8.1 $ 4.5 $ 5.1 Total Estimated 2018 Amortization $ 85.5 $ 7.2 $ 10.8 $ 10.1 $ 8.1 $ 4.5 $ 5.1 Pension Plans – Regulatory Asset $ 75.9 $ 6.8 $ 10.8 $ 9.5 $ 8.1 $ 4.5 $ 5.1 Deferred Income Taxes 2.0 0.1 — 0.1 — — — Net of Tax AOCI 7.6 0.3 — 0.5 — — — Total $ 85.5 $ 7.2 $ 10.8 $ 10.1 $ 8.1 $ 4.5 $ 5.1 AEP AEP Texas APCo I&M OPCo PSO SWEPCo OPEB – Components (in millions) Net Actuarial Loss $ 9.8 $ 0.7 $ 1.9 $ 1.0 $ 1.0 $ 0.5 $ 0.6 Prior Service Credit (69.1 ) (5.8 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2018 Amortization $ (59.3 ) $ (5.1 ) $ (8.2 ) $ (8.4 ) $ (5.9 ) $ (3.8 ) $ (4.6 ) OPEB – Regulatory Asset $ (42.9 ) $ (5.1 ) $ (4.2 ) $ (7.6 ) $ (5.9 ) $ (3.8 ) $ (2.8 ) Deferred Income Taxes (3.5 ) — (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (12.9 ) — (3.2 ) (0.6 ) — — (1.4 ) Total $ (59.3 ) $ (5.1 ) $ (8.2 ) $ (8.4 ) $ (5.9 ) $ (3.8 ) $ (4.6 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2017 2016 2015 (in millions) AEP $ 74.6 $ 72.9 $ 73.6 AEP Texas 6.0 5.2 5.0 APCo 7.4 7.3 7.2 I&M 10.7 10.9 10.6 OPCo 6.1 5.6 5.4 PSO 5.0 4.3 4.2 SWEPCo 6.0 5.7 5.7
Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans OPEB December 31, Assumption 2017 2016 2017 2016 Discount Rate 3.65 % 4.05 % 3.60 % 4.10 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2017 2016 AEP 4.80 % 4.75 % AEP Texas 4.90 % 4.85 % APCo 4.60 % 4.55 % I&M 4.85 % 4.80 % OPCo 4.95 % 4.85 % PSO 4.90 % 4.90 % SWEPCo 4.80 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member]
Actuarial Assumptions	Pension Plans OPEB Year Ended December 31, Assumptions 2017 2016 2015 2017 2016 2015 Discount Rate 4.05 % 4.30 % 4.00 % 4.10 % 4.30 % 4.00 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 6.75 % 7.00 % 6.75 % Pension Plans Year Ended December 31, Assumption – Rate of Compensation Increase (a) 2017 2016 2015 AEP 4.80 % 4.75 % 4.80 % AEP Texas 4.90 % 4.85 % 4.50 % APCo 4.60 % 4.55 % 4.45 % I&M 4.85 % 4.80 % 4.80 % OPCo 4.95 % 4.85 % 4.80 % PSO 4.90 % 4.90 % 4.80 % SWEPCo 4.80 % 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Pension Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 318.6 $ — $ — $ — $ 318.6 6.2 % International 507.7 — — — 507.7 9.8 % Options — 26.9 — — 26.9 0.5 % Common Collective Trusts (c) — — — 452.9 452.9 8.7 % Subtotal – Equities 826.3 26.9 — 452.9 1,306.1 25.2 % Fixed Income: United States Government and Agency Securities — 1,376.5 — — 1,376.5 26.6 % Corporate Debt — 1,277.0 — — 1,277.0 24.7 % Foreign Debt — 296.9 — — 296.9 5.7 % State and Local Government — 31.7 — — 31.7 0.6 % Other – Asset Backed — 10.2 — — 10.2 0.2 % Subtotal – Fixed Income — 2,992.3 — — 2,992.3 57.8 % Infrastructure (c) — — — 59.5 59.5 1.2 % Real Estate (c) — — — 290.3 290.3 5.6 % Alternative Investments (c) — — — 446.0 446.0 8.6 % Securities Lending — 501.8 — — 501.8 9.7 % Securities Lending Collateral (a) — — — (503.5 ) (503.5 ) (9.7 )% Cash and Cash Equivalents (c) 0.4 35.6 — 21.2 57.2 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 24.4 24.4 0.5 % Total $ 826.7 $ 3,556.6 $ — $ 790.8 $ 5,174.1 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share. Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 357.8 $ — $ — $ — $ 357.8 7.4 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
Pension Plan Assets Level 3 Reconciliation	Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2017 $ 57.6 $ 254.9 $ 411.1 $ 723.6 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — — — — Relating to Assets Sold During the Period — — — — Purchases and Sales — — — — Transfers into Level 3 — — — — Transfers out of Level 3 (a) (57.6 ) (254.9 ) (411.1 ) (723.6 ) Balance as of December 31, 2017 $ — $ — $ — $ — (a) The classification of Level 3 assets from the prior year was corrected in the current year presentation and included within the fair value hierarchy table as of December 31, 2017 as “Other” investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). Management concluded that these disclosure errors were immaterial individually and in the aggregate to all prior periods presented.
Other Postretirement Benefit Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 307.1 $ — $ — $ — $ 307.1 17.7 % International 306.9 — — — 306.9 17.7 % Options — 9.4 — — 9.4 0.5 % Common Collective Trusts (b) — — — 153.6 153.6 8.9 % Subtotal – Equities 614.0 9.4 — 153.6 777.0 44.8 % Fixed Income: Common Collective Trust – Debt (b) — — — 185.0 185.0 10.7 % United States Government and Agency Securities — 187.4 — — 187.4 10.8 % Corporate Debt — 214.1 — — 214.1 12.4 % Foreign Debt — 40.7 — — 40.7 2.4 % State and Local Government 49.7 16.8 — — 66.5 3.8 % Other – Asset Backed — 0.2 — — 0.2 — % Subtotal – Fixed Income 49.7 459.2 — 185.0 693.9 40.1 % Trust Owned Life Insurance: International Equities — 105.4 — — 105.4 6.1 % United States Bonds — 118.2 — — 118.2 6.8 % Subtotal – Trust Owned Life Insurance — 223.6 — — 223.6 12.9 % Cash and Cash Equivalents (b) 36.7 — — 4.2 40.9 2.4 % Other – Pending Transactions and Accrued Income (a) — — — (2.9 ) (2.9 ) (0.2 )% Total $ 700.4 $ 692.2 $ — $ 339.9 $ 1,732.5 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share. Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2017 Revenues from: External Customers $ 9,095.1 $ 4,328.9 $ 178.4 $ 1,771.4 $ 51.1 $ — $ 15,424.9 Other Operating Segments 96.9 90.4 588.3 103.7 69.7 (949.0 ) — Total Revenues $ 9,192.0 $ 4,419.3 $ 766.7 $ 1,875.1 $ 120.8 $ (949.0 ) $ 15,424.9 Asset Impairments and Other Related Charges $ 33.6 $ — $ — $ 53.5 $ — $ — $ 87.1 Depreciation and Amortization 1,142.5 667.5 102.2 24.2 0.3 60.5 (b) 1,997.2 Interest and Investment Income 6.8 7.7 1.2 10.3 23.3 (33.3 ) 16.0 Carrying Costs Income 15.2 3.6 (0.2 ) — — — 18.6 Interest Expense 540.0 244.1 72.8 18.5 63.9 (44.3 ) (b) 895.0 Income Tax Expense (Credit) 425.6 127.2 189.8 189.7 37.4 — 969.7 Income (Loss) from Continuing Operations $ 803.3 $ 636.4 $ 355.6 $ 166.0 $ (32.4 ) $ — $ 1,928.9 Income (Loss) from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 803.3 $ 636.4 $ 355.6 $ 166.0 $ (32.4 ) $ — $ 1,928.9 Gross Property Additions $ 2,343.2 $ 1,558.4 $ 1,542.8 $ 328.5 $ 15.6 $ (90.4 ) $ 5,698.1 Total Property, Plant and Equipment $ 43,294.4 $ 16,371.2 $ 7,110.2 $ 644.6 $ 374.5 $ (366.4 ) (b) $ 67,428.5 Accumulated Depreciation and Amortization 13,153.4 3,768.3 176.6 75.0 180.6 (186.9 ) (b) 17,167.0 Total Property, Plant and Equipment – Net $ 30,141.0 $ 12,602.9 $ 6,933.6 $ 569.6 $ 193.9 $ (179.5 ) (b) $ 50,261.5 Total Assets $ 37,579.7 $ 16,060.7 $ 8,141.8 $ 2,009.8 $ 3,959.1 (c) $ (3,022.0 ) (b) (d) $ 64,729.1 Investments in Equity Method Investees $ 37.1 $ 1.5 $ 742.9 $ 16.6 $ 14.2 $ — $ 812.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,038.1 $ 663.1 $ 50.0 $ — $ 2.5 $ — $ 1,753.7 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,801.4 4,705.4 2,631.3 (0.3 ) 1,281.8 — 19,419.6 Total Long-term Debt $ 11,889.5 $ 5,368.5 $ 2,681.3 $ 31.9 $ 1,284.3 $ (82.2 ) $ 21,173.3 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (b) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (b) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 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 $ 3,883.4 (c) $ (2,417.3 ) (b) (d) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 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 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (b) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (b) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 3,628.5 (c) $ (2,959.3 ) (b) (d) $ 61,683.1 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Includes the elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (d) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2017 (in millions) Revenues from: External Customers $ 141.9 $ — $ — $ 141.9 Sales to AEP Affiliates 580.5 — — 580.5 Other Revenues 0.8 — — 0.8 Total Revenues $ 723.2 $ — $ — $ 723.2 Depreciation and Amortization $ 97.1 $ — $ — $ 97.1 Interest Income 0.7 82.9 (82.4 ) (a) 1.2 Allowance for Equity Funds Used During Construction 52.3 — — 52.3 Interest Expense 68.0 82.4 (82.4 ) (a) 68.0 Income Tax Expense (Credit) 147.0 0.2 — 147.2 Net Income $ 285.8 $ 0.3 (b) $ — $ 286.1 Gross Property Additions $ 1,522.5 $ — $ — $ 1,522.5 Total Transmission Property $ 6,780.2 $ — $ — $ 6,780.2 Accumulated Depreciation and Amortization 170.4 — — 170.4 Total Transmission Property - Net $ 6,609.8 $ — $ — $ 6,609.8 Notes Receivable - Affiliated $ — $ 2,550.4 $ (2,550.4 ) (c) $ — Total Assets $ 7,072.9 $ 2,590.1 (d) $ (2,594.9 ) (e) $ 7,068.1 Total Long-Term Debt $ 2,575.0 $ 2,550.4 $ (2,575.0 ) (c) $ 2,550.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2016 (in millions) Revenues from: External Customers $ 110.4 $ — $ — $ 110.4 Sales to AEP Affiliates 367.5 — — 367.5 Other Revenues 0.1 — — 0.1 Total Revenues $ 478.0 $ — $ — $ 478.0 Depreciation and Amortization $ 65.9 $ — $ — $ 65.9 Interest Income 0.1 57.8 (57.5 ) (a) 0.4 Allowance for Equity Funds Used During Construction 52.3 — — 52.3 Interest Expense 45.6 57.9 (57.5 ) (a) 46.0 Income Tax Expense (Credit) 94.4 (0.3 ) — 94.1 Net Income (Loss) $ 193.3 $ (0.6 ) (b) $ — $ 192.7 Gross Property Additions $ 1,166.0 $ — $ — $ 1,166.0 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 $ 1,987.7 (d) $ (1,975.4 ) (e) $5,349.8 Total Long-Term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $1,932.0 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2015 (in millions) Revenues from: External Customers $ 84.3 $ — $ — $ 84.3 Sales to AEP Affiliates 225.6 — — 225.6 Other 0.3 — — 0.3 Total Revenues $ 310.2 $ — $ — $ 310.2 Depreciation and Amortization $ 42.4 $ — $ — $ 42.4 Interest Income 0.1 49.6 (49.6 ) (a) 0.1 Allowance for Equity Funds Used During Construction 53.0 — — 53.0 Interest Expense 34.4 49.8 (49.6 ) (a) 34.6 Income Tax Expense (Credit) 60.1 (0.1 ) — 60.0 Net Income (Loss) $ 133.2 $ (0.3 ) (b) $ — $ 132.9 Gross Property Additions $ 1,008.9 $ — $ — $ 1,008.9 Total Assets $ 4,143.6 $ 1,588.4 (d) $ (1,575.5 ) (e) $ 4,156.5 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes the elimination of AEPTCo Parent’s equity earnings in State Transcos. (c) Elimination of intercompany debt. (d) Includes the elimination of AEPTCo Parent’s investments in State Transcos. (e) Primarily relates to the elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	12 Months Ended
	Dec. 31, 2017
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2017 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 358.7 — 57.4 38.5 10.4 10.3 22.7 Coal Tons 2.0 — — 2.0 — — — Natural Gas MMBtus 53.7 — 1.1 0.7 — — 18.3 Heating Oil and Gasoline Gallons 6.9 1.4 1.3 0.7 1.6 0.7 0.8 Interest Rate USD $ 50.7 $ — $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP AEP Texas 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 1.5 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 of Derivative Instruments	AEP Fair Value of Derivative Instruments December 31, 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 (a) (in millions) Current Risk Management Assets $ 389.0 $ 17.5 $ 2.5 $ 409.0 $ (282.8 ) $ 126.2 Long-term Risk Management Assets 300.9 6.3 — 307.2 (25.1 ) 282.1 Total Assets 689.9 23.8 2.5 716.2 (307.9 ) 408.3 Current Risk Management Liabilities 334.6 9.0 — 343.6 (282.0 ) 61.6 Long-term Risk Management Liabilities 280.6 58.3 8.6 347.5 (25.5 ) 322.0 Total Liabilities 615.2 67.3 8.6 691.1 (307.5 ) 383.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 74.7 $ (43.5 ) $ (6.1 ) $ 25.1 $ (0.4 ) $ 24.7 Fair Value of Derivative Instruments December 31, 2016 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 (a) (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 AEP Texas Fair Value of Derivative Instruments December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 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 $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.4 $ (0.2 ) $ 0.2 APCo Fair Value of Derivative Instruments December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 75.6 $ (50.7 ) $ 24.9 Long-term Risk Management Assets 2.4 (1.3 ) 1.1 Total Assets 78.0 (52.0 ) 26.0 Current Risk Management Liabilities 50.6 (49.3 ) 1.3 Long-term Risk Management Liabilities 1.4 (1.2 ) 0.2 Total Liabilities 52.0 (50.5 ) 1.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 26.0 $ (1.5 ) $ 24.5 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 $ 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 47.2 $ (39.6 ) $ 7.6 Long-term Risk Management Assets 1.6 (0.9 ) 0.7 Total Assets 48.8 (40.5 ) 8.3 Current Risk Management Liabilities 48.5 (45.0 ) 3.5 Long-term Risk Management Liabilities 0.9 (0.8 ) 0.1 Total Liabilities 49.4 (45.8 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.6 ) $ 5.3 $ 4.7 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 6.4 — 6.4 Long-term Risk Management Liabilities 126.0 — 126.0 Total Liabilities 132.4 — 132.4 Total MTM Derivative Contract Net Liabilities $ (131.8 ) $ — $ (131.8 ) 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 $ 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 6.6 $ (0.2 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 6.6 (0.2 ) 6.4 Current Risk Management Liabilities 0.2 (0.2 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.2 (0.2 ) — Total MTM Derivative Contract Net Assets $ 6.4 $ — $ 6.4 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 December 31, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 7.0 $ (0.6 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 7.0 (0.6 ) 6.4 Current Risk Management Liabilities 0.8 (0.6 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.8 (0.6 ) 0.2 Total MTM Derivative Contract Net Assets $ 6.2 $ — $ 6.2 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 Year Ended December 31, 2017 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.1 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 42.8 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.6 5.3 — — 0.1 Purchased Electricity for Resale 5.6 — 2.0 0.6 — — — Other Operation 0.8 0.1 0.1 0.1 0.1 0.1 0.1 Maintenance 0.7 0.2 0.1 0.1 0.1 0.1 0.1 Regulatory Assets (a) (29.4 ) — — (7.4 ) (22.0 ) — 0.3 Regulatory Liabilities (a) 109.4 0.1 40.4 15.9 — 24.8 24.3 Total Gain (Loss) on Risk Management Contracts $ 136.0 $ 0.4 $ 43.2 $ 14.6 $ (21.8 ) $ 25.0 $ 24.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — — Generation & Marketing Revenues 59.4 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 — 3.5 0.3 — — — Other Operation (1.6 ) (0.4 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance (1.8 ) (0.4 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.8 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 0.4 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 0.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — — Generation & Marketing Revenues 54.9 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 — 2.0 0.4 — — — Other Operation (3.3 ) (0.8 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance (3.3 ) (0.7 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 0.4 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 — 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ (1.1 ) $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 (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 Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassed to Reclassed to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) AEP Texas $ (4.5 ) $ (0.9 ) $ (5.4 ) $ (0.9 ) APCo 2.2 0.7 2.9 0.7 I&M (10.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 1.9 1.1 3.0 1.1 PSO 2.6 0.8 3.4 0.8 SWEPCo (6.0 ) (1.4 ) (7.4 ) (1.4 ) Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 22.0 $ — $ 11.2 $ — Hedging Liabilities (a) 65.5 — 46.7 — AOCI Gain (Loss) Net of Tax (28.4 ) (13.0 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 5.5 (0.8 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Liabilities Subject to Cross Default Provisions	AEP Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision December 31, Netting Arrangements Collateral Posted is Triggered (in millions) 2017 $ 243.6 $ 1.3 $ 223.1 2016 259.6 0.4 235.8

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Book Values and Fair Values of Long-term Debt	December 31, 2017 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 21,173.3 $ 23,649.6 $ 20,391.2 (a) $ 22,211.9 (a) AEP Texas 3,649.3 3,964.8 3,217.7 3,463.2 AEPTCo 2,550.4 2,782.9 1,932.0 1,984.3 APCo 3,980.1 4,782.6 4,033.9 4,613.2 I&M 2,745.1 3,014.7 2,471.4 2,661.6 OPCo 1,719.3 2,064.3 1,763.9 2,092.5 PSO 1,286.5 1,457.1 1,286.0 1,419.0 SWEPCo 2,441.9 2,645.9 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 7 for additional information.
Other Temporary Investments	December 31, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 220.1 $ — $ — $ 220.1 Fixed Income Securities – Mutual Funds (b) 104.3 — (1.4 ) 102.9 Equity Securities – Mutual Funds 17.0 19.7 — 36.7 Total Other Temporary Investments $ 341.4 $ 19.7 $ (1.4 ) $ 359.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (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	Years Ended December 31, 2017 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 14.2 2.3 10.7 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — —
Nuclear Trust Fund Investments	December 31, 2017 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 $ 17.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 981.2 29.7 (3.6 ) 785.4 27.1 (5.5 ) Corporate Debt 58.7 3.8 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 8.8 0.8 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,048.7 34.3 (5.0 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,461.7 868.2 (75.5 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,527.6 $ 902.5 $ (80.5 ) $ 2,256.2 $ 707.7 $ (87.2 )
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2017 2016 2015 (in millions) Proceeds from Investment Sales $ 2,256.3 $ 2,957.7 $ 2,218.4 Purchases of Investments 2,300.5 3,000.0 2,272.0 Gross Realized Gains on Investment Sales 200.7 46.1 69.1 Gross Realized Losses on Investment Sales 146.0 24.4 53.0
Investments Classified by Contractual Maturity Date [Table Text Block]	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 387.3 After 1 year through 5 years 287.4 After 5 years through 10 years 204.4 After 10 years 169.6 Total $ 1,048.7
Fair Value, Assets and Liabilities Measured on Recurring Basis	AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 183.2 $ — $ — $ 36.9 $ 220.1 Fixed Income Securities – Mutual Funds 102.9 — — — 102.9 Equity Securities – Mutual Funds (b) 36.7 — — — 36.7 Total Other Temporary Investments 322.8 — — 36.9 359.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 3.9 391.2 274.1 (285.4 ) 383.8 Cash Flow Hedges: Commodity Hedges (c) — 17.3 4.7 — 22.0 Fair Value Hedges — 2.5 — — 2.5 Total Risk Management Assets 3.9 411.0 278.8 (285.4 ) 408.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities – Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,795.9 $ 1,459.7 $ 278.8 $ (238.8 ) $ 3,295.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.1 $ 392.5 $ 196.9 $ (285.0 ) $ 309.5 Cash Flow Hedges: Commodity Hedges (c) — 23.9 41.6 — 65.5 Fair Value Hedges — 8.6 — — 8.6 Total Risk Management Liabilities $ 5.1 $ 425.0 $ 238.5 $ (285.0 ) $ 383.6 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 and Other Cash Deposits (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 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 155.2 $ — $ — $ — $ 155.2 Risk Management Assets Risk Management Commodity Contracts (c) — 0.5 — — 0.5 Total Assets $ 155.2 $ 0.5 $ — $ — $ 155.7 AEP Texas 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 $ 146.3 $ — $ — $ — $ 146.3 Risk Management Assets Risk Management Commodity Contracts (c) — 0.4 — (0.2 ) 0.2 Total Assets $ 146.3 $ 0.4 $ — $ (0.2 ) $ 146.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 16.3 $ — $ — $ — $ 16.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 52.5 25.1 (51.6 ) 26.0 Total Assets $ 16.3 $ 52.5 $ 25.1 $ (51.6 ) $ 42.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 51.2 $ 0.4 $ (50.1 ) $ 1.5 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 39.4 $ 9.1 $ (40.2 ) $ 8.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities – Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,469.2 $ 1,088.1 $ 9.1 $ (30.5 ) $ 2,535.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 47.6 $ 1.5 $ (45.5 ) $ 3.6 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ — $ — $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 132.4 $ — $ 132.4 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 6.4 $ (0.2 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.2 $ (0.2 ) $ — 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 December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 6.7 $ (0.6 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.8 $ (0.6 ) $ 0.2 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 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 December 31, 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 periods 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. 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.
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 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) 37.3 17.2 4.0 (1.4 ) 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) 33.6 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (18.8 ) — — — — — Settlements (50.6 ) (18.9 ) (7.1 ) 7.4 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.2 — — — — — Transfers out of Level 3 (e) (10.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 30.2 25.0 7.9 (19.4 ) 6.2 6.0 Balance as of December 31, 2017 $ 40.3 $ 24.7 $ 7.6 $ (132.4 ) $ 6.2 $ 5.9 Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 (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 assets/liabilities or accounts payable.
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Valuation Techniques [Table Text Block]	Significant Unobservable Inputs December 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 225.1 $ 233.7 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 263.00 $ 36.32 Counterparty Credit Risk (b) 8 456 180 Natural Gas Contracts — 0.2 Discounted Cash Flow Forward Market Price (c) 2.37 2.96 2.62 FTRs 53.7 4.6 Discounted Cash Flow Forward Market Price (a) (55.62 ) 54.88 0.41 Total $ 278.8 $ 238.5 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 December 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.4 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 24.3 — Discounted Cash Flow Forward Market Price (0.36 ) 7.15 1.62 Total $ 25.1 $ 0.4 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 December 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.5 $ 0.3 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 8.6 1.2 Discounted Cash Flow Forward Market Price (0.36 ) 5.75 0.86 Total $ 9.1 $ 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 December 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 132.4 Discounted Cash Flow Forward Market Price (a) $ 30.52 $ 170.43 $ 44.62 Counterparty Credit Risk (b) 8 190 136 Total $ — $ 132.4 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 December 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 6.4 $ 0.2 Discounted Cash Flow Forward Market Price $ (6.62 ) $ 1.41 $ (0.76 ) 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 December 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 0.2 Discounted Cash Flow Forward Market Price (c) $ 2.37 $ 2.96 $ 2.62 FTRs 6.7 0.6 Discounted Cash Flow Forward Market Price (a) (6.62 ) 1.41 (0.76 ) Total $ 6.7 $ 0.8 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. (c) Represents market prices in dollars per MMBtu.
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 (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Impact of Tax Reform on Financial Statements	Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Decrease in Deferred Income Tax Liabilities $ 6,101.1 $ 807.1 $ 558.6 $ 1,296.4 $ 808.7 $ 743.1 $ 538.6 $ 782.9
Results of Decrease in Deferred Income Tax Liabilities	Year Ended December 31, 2017 AEP (c) AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Increase (Decrease) in Income Tax Expense (a) $ (16.5 ) $ (117.4 ) (b) $ 0.6 $ 5.7 $ 2.3 $ (14.3 ) (b) $ 2.8 $ 0.7 Decrease in Regulatory Assets 470.2 12.1 66.9 129.1 85.3 62.7 8.3 69.8 Increase in Regulatory Liabilities 5,614.4 677.6 492.3 1,173.0 725.7 666.1 533.1 713.8 (a) In 2017, in contemplation of corporate federal tax reform, the Registrants adopted a method under Internal Revenue Section 162 for deducting repair and maintenance costs associated with transmission and distribution property. This change resulted in a decrease in state income tax expense of approximately $10 million that has been excluded from the tables above. (b) AEP Texas and OPCo recorded favorable adjustments to income tax expense of approximately $113 million and $16 million related to previously owned deregulated generation assets and certain deferred fuel amounts, respectively.
Details of Income Taxes as Reported	Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (4.0 ) $ (85.7 ) $ (127.5 ) $ 15.3 $ (106.5 ) $ 11.2 $ (77.1 ) $ (30.1 ) Deferred 856.6 63.3 256.0 166.9 202.1 141.3 122.7 84.8 Deferred Investment Tax Credits 48.6 (1.6 ) — (0.1 ) (4.7 ) — (1.6 ) (1.4 ) Total Federal 901.2 (24.0 ) 128.5 182.1 90.9 152.5 44.0 53.3 State and Local: Current 16.0 0.6 1.9 (1.4 ) (8.1 ) 0.2 (0.2 ) (0.9 ) Deferred 44.9 — 16.8 4.6 (1.4 ) 6.6 2.0 (4.3 ) Deferred Investment Tax Credits 7.6 — — — — — 4.3 — Total State and Local 68.5 0.6 18.7 3.2 (9.5 ) 6.8 6.1 (5.2 ) Income Tax Expense (Credit) Before Discontinued Operations $ 969.7 $ (23.4 ) $ 147.2 $ 185.3 $ 81.4 $ 159.3 $ 50.1 $ 48.1 Year Ended December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 40.9 $ (129.4 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 29.9 205.9 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (1.7 ) — (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 69.1 76.5 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) (8.8 ) 0.4 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) (0.4 ) 17.2 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — — — 3.2 — Total State and Local (31.8 ) (9.2 ) 17.6 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 59.9 $ 94.1 $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 Year Ended December 31, 2015 AEP AEP Texas AEPTCo (in millions) Federal: Current $ 107.3 $ 61.4 $ (126.3 ) Deferred 774.8 (7.1 ) 171.3 Deferred Investment Tax Credits — (1.7 ) — Total Federal 882.1 52.6 45.0 State and Local: Current 14.5 5.6 3.1 Deferred 23.0 — 11.9 Total State and Local 37.5 5.6 15.0 Income Tax Expense Before Discontinued Operations $ 919.6 $ 58.2 $ 60.0 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	AEP Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 1,928.9 $ 618.0 $ 2,052.3 Discontinued Operations (Net of Income Tax of $0, $0 and $6.2 in 2017, 2016 and 2015, Respectively) — 2.5 (283.7 ) Income Tax Expense (Credit) Before Discontinued Operations 969.7 (73.7 ) 919.6 Pretax Income $ 2,898.6 $ 546.8 $ 2,688.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 1,014.5 $ 191.4 $ 940.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 60.2 41.7 53.6 Investment Tax Credit Amortization (18.8 ) (12.3 ) (11.6 ) State and Local Income Taxes, Net 54.7 (20.7 ) 24.4 Removal Costs (32.7 ) (39.8 ) (28.8 ) AFUDC (37.4 ) (44.8 ) (51.6 ) Valuation Allowance (1.8 ) (128.3 ) 17.2 U.K. Windfall Tax — (12.9 ) — Tax Reform Adjustments (26.7 ) — — Tax Adjustments (35.8 ) (43.9 ) (20.1 ) Other (6.5 ) (4.1 ) (4.4 ) Income Tax Expense (Credit) Before Discontinued Operations $ 969.7 $ (73.7 ) $ 919.6 Effective Income Tax Rate 33.5 % (13.5 ) % 34.2 % AEP Texas Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 310.5 $ 146.6 $ 120.3 Discontinued Operations (Net of Income Tax of $0, $27.6 and $1.8 in 2017, 2016 and 2015, Respectively) — 48.8 1.4 Income Tax Expense (23.4 ) 59.9 58.2 Pretax Income $ 287.1 $ 255.3 $ 179.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 100.5 $ 89.4 $ 63.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.7 0.5 0.5 Investment Tax Credit Amortization (1.6 ) (1.7 ) (1.7 ) State and Local Income Taxes, Net 0.4 (6.0 ) 3.6 Parent Company Loss Benefit — (2.5 ) (3.1 ) Tax Reform Adjustments (117.4 ) — — Tax Adjustments (4.2 ) (4.9 ) (1.6 ) U.K. Windfall Tax — (12.9 ) — Other (1.8 ) (2.0 ) (2.5 ) Income Tax Expense (Credit) Before Discontinued Operations $ (23.4 ) $ 59.9 $ 58.2 Effective Income Tax Rate (8.2 ) % 23.5 % 32.4 % AEPTCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 286.1 $ 192.7 $ 132.9 Income Tax Expense 147.2 94.1 60.0 Pretax Income $ 433.3 $ 286.8 $ 192.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 151.7 $ 100.4 $ 67.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: AFUDC (18.3 ) (18.3 ) (18.6 ) State and Local Income Taxes, Net 12.2 11.4 9.8 Tax Reform Adjustments 0.6 — — Other 1.0 0.6 1.3 Income Tax Expense $ 147.2 $ 94.1 $ 60.0 Effective Income Tax Rate 34.0 % 32.8 % 31.1 % APCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 331.3 $ 369.1 $ 340.6 Income Tax Expense 185.3 199.1 194.3 Pretax Income $ 516.6 $ 568.2 $ 534.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 180.8 $ 198.9 $ 187.2 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 18.0 19.3 19.8 Investment Tax Credit Amortization (0.1 ) (0.1 ) (0.3 ) State and Local Income Taxes, Net 3.5 6.0 7.2 Removal Costs (12.4 ) (12.0 ) (9.9 ) AFUDC (5.0 ) (6.1 ) (7.0 ) Valuation Allowance — (1.7 ) 1.7 Tax Reform Adjustments 4.3 — — Other (3.8 ) (5.2 ) (4.4 ) Income Tax Expense $ 185.3 $ 199.1 $ 194.3 Effective Income Tax Rate 35.9 % 35.0 % 36.3 % I&M Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 186.7 $ 239.9 $ 204.8 Income Tax Expense 81.4 67.5 96.1 Pretax Income $ 268.1 $ 307.4 $ 300.9 Income Taxes on Pretax Income at Statutory Rate (35%) $ 93.8 $ 107.6 $ 105.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 11.4 6.7 9.5 Investment Tax Credit Amortization (4.7 ) (4.7 ) (3.3 ) State and Local Income Taxes, Net (1.0 ) 2.4 5.8 Removal Costs (13.3 ) (21.3 ) (12.6 ) AFUDC (5.6 ) (7.3 ) (6.2 ) Tax Adjustments 2.7 (14.2 ) (4.2 ) Tax Reform Adjustments (2.9 ) — — Other 1.0 (1.7 ) 1.8 Income Tax Expense $ 81.4 $ 67.5 $ 96.1 Effective Income Tax Rate 30.4 % 22.0 % 31.9 % OPCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 323.9 $ 282.2 $ 232.7 Income Tax Expense 159.3 143.8 126.5 Pretax Income $ 483.2 $ 426.0 $ 359.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 169.1 $ 149.1 $ 125.7 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.6 7.1 8.2 Investment Tax Credit Amortization — — (0.1 ) State and Local Income Taxes, Net 4.4 3.8 0.7 Tax Reform Adjustments (14.4 ) — — Other (7.4 ) (16.2 ) (8.0 ) Income Tax Expense $ 159.3 $ 143.8 $ 126.5 Effective Income Tax Rate 33.0 % 33.8 % 35.2 % PSO Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 72.0 $ 100.0 $ 92.5 Income Tax Expense 50.1 54.4 51.3 Pretax Income $ 122.1 $ 154.4 $ 143.8 Income Taxes on Pretax Income at Statutory Rate (35%) $ 42.7 $ 54.0 $ 50.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.3 0.8 0.5 Investment Tax Credit Amortization (1.6 ) (1.4 ) (1.8 ) State and Local Income Taxes, Net 4.0 4.2 5.1 AFUDC (0.2 ) (2.2 ) (3.1 ) Tax Reform Adjustments 2.8 — — Other 2.1 (1.0 ) 0.3 Income Tax Expense $ 50.1 $ 54.4 $ 51.3 Effective Income Tax Rate 41.0 % 35.2 % 35.7 % SWEPCo Years Ended December 31, 2017 2016 2015 (in millions) Net Income $ 137.5 $ 169.7 $ 196.0 Income Tax Expense 48.1 52.1 84.8 Pretax Income $ 185.6 $ 221.8 $ 280.8 Income Taxes on Pretax Income at Statutory Rate (35%) $ 65.0 $ 77.6 $ 98.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 1.9 3.2 3.1 Depletion (5.7 ) (5.5 ) (5.5 ) Investment Tax Credit Amortization (1.4 ) (1.2 ) (1.4 ) State and Local Income Taxes, Net (2.3 ) (14.7 ) 4.8 AFUDC (0.9 ) (3.9 ) (9.2 ) Tax Adjustments (9.9 ) (0.9 ) (3.9 ) Tax Reform Adjustments (0.4 ) — — Other 1.8 (2.5 ) (1.4 ) Income Tax Expense $ 48.1 $ 52.1 $ 84.8 Effective Income Tax Rate 25.9 % 23.5 % 30.2 %
Reconciliation of Significant Temporary Differences	AEP December 31, 2017 2016 (in millions) Deferred Tax Assets $ 3,504.6 $ 2,753.0 Deferred Tax Liabilities (10,318.5 ) (14,637.4 ) Net Deferred Tax Liabilities $ (6,813.9 ) $ (11,884.4 ) Property Related Temporary Differences $ (5,680.6 ) $ (8,758.1 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 1,064.8 (292.2 ) Deferred State Income Taxes (1,124.4 ) (976.6 ) Securitized Assets (257.7 ) (535.6 ) Regulatory Assets (500.3 ) (896.9 ) Deferred Income Taxes on Other Comprehensive Loss 25.7 88.7 Accrued Nuclear Decommissioning (457.0 ) (666.8 ) Net Operating Loss Carryforward 86.6 101.2 Tax Credit Carryforward 174.7 45.1 Investment in Partnership (222.0 ) (349.6 ) Valuation Allowance — (1.8 ) All Other, Net 76.3 358.2 Net Deferred Tax Liabilities $ (6,813.9 ) $ (11,884.4 ) AEP Texas December 31, 2017 2016 (in millions) Deferred Tax Assets $ 221.0 $ 135.8 Deferred Tax Liabilities (1,134.1 ) (1,667.5 ) Net Deferred Tax Liabilities $ (913.1 ) $ (1,531.7 ) Property Related Temporary Differences $ (791.5 ) $ (1,056.1 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 140.9 (5.7 ) Deferred State Income Taxes (27.5 ) (24.2 ) Regulatory Assets (36.4 ) (61.3 ) Securitized Transition Assets (190.5 ) (407.0 ) Deferred Income Taxes on Other Comprehensive Loss 4.1 8.0 Deferred Revenues 10.9 18.0 All Other, Net (23.1 ) (3.4 ) Net Deferred Tax Liabilities $ (913.1 ) $ (1,531.7 ) AEPTCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 162.7 $ 61.4 Deferred Tax Liabilities (764.4 ) (923.5 ) Net Deferred Tax Liabilities $ (601.7 ) $ (862.1 ) Property Related Temporary Differences $ (654.7 ) $ (825.6 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 89.7 (37.2 ) Deferred State Income Taxes (77.4 ) (55.6 ) Deferred Federal Income Taxes on Deferred State Income Taxes 16.3 19.5 Net Operating Loss Carryforward 16.8 33.3 Valuation Allowance — 0.1 Tax Credit Carryforward 0.3 — All Other, Net 7.3 3.4 Net Deferred Tax Liabilities $ (601.7 ) $ (862.1 ) APCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 614.4 $ 413.5 Deferred Tax Liabilities (2,180.1 ) (3,085.8 ) Net Deferred Tax Liabilities $ (1,565.7 ) $ (2,672.3 ) Property Related Temporary Differences $ (1,308.2 ) $ (2,031.9 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 228.0 (73.1 ) Deferred State Income Taxes (335.7 ) (319.3 ) Regulatory Assets (83.9 ) (159.9 ) Securitized Assets (59.3 ) (106.9 ) Deferred Income Taxes on Other Comprehensive Loss (0.4 ) 4.5 Tax Credit Carryforward 16.6 11.7 All Other, Net (22.8 ) 2.6 Net Deferred Tax Liabilities $ (1,565.7 ) $ (2,672.3 ) I&M December 31, 2017 2016 (in millions) Deferred Tax Assets $ 1,096.4 $ 912.9 Deferred Tax Liabilities (2,050.2 ) (2,440.3 ) Net Deferred Tax Liabilities $ (953.8 ) $ (1,527.4 ) Property Related Temporary Differences $ (403.0 ) $ (579.4 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 137.6 (50.4 ) Deferred State Income Taxes (180.6 ) (158.7 ) Deferred Income Taxes on Other Comprehensive Loss 3.9 8.8 Accrued Nuclear Decommissioning (457.0 ) (666.8 ) Regulatory Assets (43.8 ) (81.0 ) Net Operating Loss Carryforward 1.6 7.1 All Other, Net (12.5 ) (7.0 ) Net Deferred Tax Liabilities $ (953.8 ) $ (1,527.4 ) OPCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 286.0 $ 232.4 Deferred Tax Liabilities (1,048.9 ) (1,578.5 ) Net Deferred Tax Liabilities $ (762.9 ) $ (1,346.1 ) Property Related Temporary Differences $ (761.2 ) $ (1,090.8 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 127.3 (43.6 ) Deferred State Income Taxes (41.7 ) (34.6 ) Regulatory Assets (107.7 ) (174.1 ) Deferred Income Taxes on Other Comprehensive Loss (0.6 ) (1.6 ) Deferred Fuel and Purchased Power (24.5 ) (117.6 ) All Other, Net 45.5 116.2 Net Deferred Tax Liabilities $ (762.9 ) $ (1,346.1 ) PSO December 31, 2017 2016 (in millions) Deferred Tax Assets $ 269.2 $ 153.8 Deferred Tax Liabilities (911.2 ) (1,212.6 ) Net Deferred Tax Liabilities $ (642.0 ) $ (1,058.8 ) Property Related Temporary Differences $ (623.8 ) $ (927.3 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 111.6 (3.2 ) Deferred State Income Taxes (142.7 ) (128.5 ) Regulatory Assets (34.4 ) (67.6 ) Deferred Income Taxes on Other Comprehensive Loss (0.8 ) (1.8 ) Deferred Federal Income Taxes on Deferred State Income Taxes 33.5 50.6 Net Operating Loss Carryforward 23.1 16.5 Tax Credit Carryforward 0.7 — All Other, Net (9.2 ) 2.5 Net Deferred Tax Liabilities $ (642.0 ) $ (1,058.8 ) SWEPCo December 31, 2017 2016 (in millions) Deferred Tax Assets $ 349.4 $ 230.5 Deferred Tax Liabilities (1,267.1 ) (1,837.4 ) Net Deferred Tax Liabilities $ (917.7 ) $ (1,606.9 ) Property Related Temporary Differences $ (908.8 ) $ (1,445.2 ) Amounts Due to/(from) Customers for Future Federal Income Taxes 135.8 (48.2 ) Deferred State Income Taxes (189.2 ) (175.1 ) Regulatory Assets (30.8 ) (40.7 ) Deferred Income Taxes on Other Comprehensive Loss 1.3 5.1 Capital/Impairment Loss - Turk Plant 17.4 20.3 Net Operating Loss Carryforward 38.7 40.3 Tax Credit Carryforward 0.8 0.1 All Other, Net 17.1 36.5 Net Deferred Tax Liabilities $ (917.7 ) $ (1,606.9 )
Federal Net Income Tax Operating Loss Carryforwards	Year Ended December 31, Company 2017 (in millions) AEP $ 230.1 AEP Texas 261.8 AEPTCo 344.1 I&M 332.6 PSO 213.9 SWEPCo 87.6
State Net Income Tax Operating Loss Carryforwards	State Net Income Tax Operating Loss Year of Company State/Municipality Carryforward Expiration (in millions) AEP Arkansas $ 72.0 2022 AEP Kentucky 157.6 2037 AEP Louisiana 543.1 2037 AEP Oklahoma 799.8 2037 AEP Tennessee 27.9 2032 AEP Virginia 17.8 2037 AEP West Virginia 29.2 2037 AEP Ohio Municipal 106.3 2022 AEPTCo Oklahoma 296.9 2037 AEPTCo Ohio Municipal 64.2 2022 I&M West Virginia 14.1 2037 PSO Oklahoma 477.0 2037 SWEPCo Arkansas 71.2 2022 SWEPCo Louisiana 533.4 2037
Summary of Tax Credit Carryforwards	Federal Tax State Tax Credit Credit Total Federal Carryforward Total State Carryforward Tax Credit Subject to Tax Credit Subject to Company Carryforward Expiration Carryforward Expiration (in millions) AEP $ 174.7 $ 145.8 $ 31.0 $ 31.0 AEP Texas 0.6 0.3 — — AEPTCo 0.3 0.1 — — APCo 16.6 6.1 — — I&M 10.6 10.1 — — OPCo 14.8 1.0 — — PSO 0.7 0.7 31.0 31.0 SWEPCo 0.8 0.7 — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 1.7 $ — $ — $ 0.5 $ — $ — $ — $ — Interest Income 6.1 1.1 — — 1.0 1.6 — — Reversal of Prior Period Interest Expense — — — — — — — — Year Ended December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ — $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.2 — 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 0.8 — — — — 0.7 1.4 Year Ended December 31, 2015 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.2 $ — $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 0.2 — — — — — — Reversal of Prior Period Interest Expense — — — — — — — —
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2017 2016 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 3.6 $ 8.3 $ 2.9 $ 5.8 AEP Texas 2.8 0.1 2.1 0.3 AEPTCo — — — — APCo — 1.0 — 0.1 I&M — 1.3 — 0.9 OPCo 0.3 1.0 — 1.7 PSO 0.6 — 0.6 — SWEPCo — — 0.1 —
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2017 $ 98.8 $ 6.5 $ — $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 Increase – Tax Positions Taken During a Prior Period 4.5 2.0 — — 0.2 — 0.1 1.7 Decrease – Tax Positions Taken During a Prior Period (28.0 ) (12.3 ) — — (0.5 ) — (0.9 ) (5.4 ) Increase – Tax Positions Taken During the Current Year 3.4 — — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Settlements with Taxing Authorities 7.9 3.0 — — (0.3 ) — 0.7 1.6 Decrease – Lapse of the Applicable Statute of Limitations — — — — — — — — Balance as of December 31, 2017 $ 86.6 $ (0.8 ) $ — $ — $ 3.2 $ 6.9 $ — $ (0.8 ) AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 27.8 $ — $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 6.5 — — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (15.0 ) — (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) (12.8 ) — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — — — Balance as of December 31, 2016 $ 98.8 $ 6.5 $ — $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ 22.6 $ — $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 5.2 — 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — — — Balance as of December 31, 2015 $ 187.0 $ 27.8 $ — $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2017 2016 2015 (in millions) AEP $ 10.5 $ 15.8 $ 100.2 AEP Texas (0.5 ) 4.2 26.0 AEPTCo — — — APCo — — 0.2 I&M 2.1 2.5 1.6 OPCo 4.5 4.4 4.5 PSO — 0.1 0.9 SWEPCo (0.5 ) 0.8 6.0

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Lease Rental Costs	Year Ended December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 231.3 $ 10.5 $ 1.7 $ 17.5 $ 88.4 $ 8.2 $ 4.4 $ 5.3 Amortization of Capital Leases 66.3 4.0 — 6.9 11.1 4.1 4.0 11.2 Interest on Capital Leases 16.7 0.8 — 3.7 3.2 0.5 0.6 3.6 Total Lease Rental Costs $ 314.3 $ 15.3 $ 1.7 $ 28.1 $ 102.7 $ 12.8 $ 9.0 $ 20.1 Year Ended December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 9.8 (a) $ 0.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 3.4 — 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 0.6 — 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 13.8 $ 0.9 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 8.1 (a) $ 0.5 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 2.9 — 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.4 — 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (b) $ 11.4 $ 0.5 $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 (a) Amounts include lease expenses related to AEP Texas Wind Farms that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for each of the years ended December 31, 2016 and 2015, respectively. See Note 7 for additional information. (b) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statement of income in the amount of $89 million for the year ended December 31, 2015. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 141.7 $ — $ — $ 42.5 $ 27.2 $ — $ 8.9 $ 33.4 Other Property, Plant and Equipment 373.3 32.7 0.2 18.0 34.0 22.8 18.0 122.4 Total Property, Plant and Equipment 515.0 32.7 0.2 60.5 61.2 22.8 26.9 155.8 Accumulated Amortization 229.0 10.0 — 19.0 21.1 10.6 15.3 94.0 Net Property, Plant and Equipment Under Capital Leases $ 286.0 $ 22.7 $ 0.2 $ 41.5 $ 40.1 $ 12.2 $ 11.6 $ 61.8 Obligations Under Capital Leases: Noncurrent Liability $ 238.8 $ 18.5 $ 0.1 $ 34.9 $ 34.3 $ 7.9 $ 8.3 $ 57.8 Liability Due Within One Year 59.0 4.2 0.1 6.6 5.8 4.3 3.5 11.2 Total Obligations Under Capital Leases $ 297.8 $ 22.7 $ 0.2 $ 41.5 $ 40.1 $ 12.2 $ 11.8 $ 69.0 December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ — $ — $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 26.1 — 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 26.1 — 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 7.7 — 18.1 25.4 11.6 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 18.4 $ — $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 14.8 $ — $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 3.6 — 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 18.4 $ — $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3
Future Minimum Lease Payments	Capital Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 76.6 $ 5.1 $ 0.1 $ 10.0 $ 11.0 $ 4.7 $ 3.8 $ 14.3 2019 60.4 4.0 0.1 7.9 7.2 2.4 2.5 12.7 2020 49.7 3.4 — 7.0 6.4 1.8 1.7 10.9 2021 42.6 3.1 — 6.8 5.9 1.6 1.3 10.0 2022 35.1 2.6 — 6.4 5.4 1.1 1.0 8.9 Later Years 106.2 8.3 — 18.8 25.2 2.0 2.6 25.6 Total Future Minimum Lease Payments 370.6 26.5 0.2 56.9 61.1 13.6 12.9 82.4 Less Estimated Interest Element 72.8 3.8 — 15.4 21.0 1.4 1.3 13.4 Estimated Present Value of Future Minimum Lease Payments $ 297.8 $ 22.7 $ 0.2 $ 41.5 $ 40.1 $ 12.2 $ 11.6 $ 69.0 Noncancelable Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 245.9 $ 11.6 $ 1.7 $ 17.3 $ 91.3 $ 11.3 $ 4.8 $ 6.0 2019 237.9 10.7 1.3 15.6 90.3 10.3 4.3 5.7 2020 227.6 9.8 1.0 14.4 86.9 8.7 3.8 5.3 2021 210.7 8.9 0.4 12.0 82.4 6.3 2.9 4.9 2022 201.1 7.9 — 10.9 81.4 5.4 2.5 4.3 Later Years 137.1 21.5 — 23.3 16.3 19.5 6.5 9.5 Total Future Minimum Lease Payments $ 1,260.3 $ 70.4 $ 4.4 $ 93.5 $ 448.6 $ 61.5 $ 24.8 $ 35.7
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 43.2 AEP Texas 10.0 APCo 8.8 I&M 3.3 OPCo 6.4 PSO 3.6 SWEPCo 3.7
Rockport Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 2018 $ 147.8 $ 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 2022 147.2 73.6 Total Future Minimum Lease Payments $ 738.4 $ 369.2 (a) AEP’s future minimum lease payments include equal shares from AEGCo and I&M.

Financing Activities (Tables)

Financing Activities (Tables)	12 Months Ended
	Dec. 31, 2017
AEP Common Stock	Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Issued 162,124 — Treasury Stock Reissued — (131,546 ) (a) Balance, December 31, 2017 512,210,644 20,205,046 (a) Reissued Treasury Stock used to fulfill share commitments related to AEP’s Share-based Compensation. See “Shared-based Compensation Plans” section of Note 15 for additional information.
Long-term Debt	Weighted Average Interest Rate Ranges as of Outstanding as of Interest Rate as of December 31, December 31, Company Maturity December 31, 2017 2017 2016 2017 2016 AEP (in millions) Senior Unsecured Notes 2017-2047 4.62% 2.15%-8.13% 1.65%-8.13% $ 16,478.3 $ 14,761.0 (f) Pollution Control Bonds (a) 2017-2042 (b) 3.06% 1.54%-6.30% 0.69%-6.30% 1,621.7 1,725.1 Notes Payable – Nonaffiliated (c) 2017-2032 3.00% 2.03%-6.37% 1.456%-6.37% 260.8 326.9 Securitization Bonds 2017-2028 (d) 3.70% 1.98%-5.31% 0.88%-5.31% 1,416.5 1,705.0 Spent Nuclear Fuel Obligation (e) 268.6 266.3 Other Long-term Debt 2017-2059 2.75% 1.15%-13.718% 1.15%-13.718% 1,127.4 1,606.9 Total Long-term Debt Outstanding $ 21,173.3 $ 20,391.2 (f) AEP Texas Senior Unsecured Notes 2018-2047 4.12% 2.40%-6.76% 2.61%-6.76% $ 1,932.2 $ 1,241.3 Pollution Control Bonds (a) 2017-2030 4.39% 1.75%-6.30% 4.00%-6.30% 490.5 530.3 Securitization Bonds 2017-2024 (d) 4.05% 1.98%-5.31% 0.88%-5.31% 1,026.1 1,245.8 Other Long-term Debt 2019-2059 2.76% 2.75%-4.50% 2.438%-4.50% 200.5 200.3 Total Long-term Debt Outstanding $ 3,649.3 $ 3,217.7 AEPTCo Senior Unsecured Notes 2018-2047 3.85% 2.68%-5.52% 2.68%-5.52% $ 2,550.4 $ 1,932.0 Total Long-term Debt Outstanding $ 2,550.4 $ 1,932.0 APCo Senior Unsecured Notes 2017-2045 5.20% 3.30%-7.00% 3.40%-7.00% $ 3,045.1 $ 2,972.4 Pollution Control Bonds (a) 2018-2042 (b) 2.44% 1.625%-5.38% 0.69%-5.38% 512.2 615.8 Securitization Bonds 2023-2028 (d) 2.98% 2.008%-3.772% 2.008%-3.772% 295.9 318.9 Other Long-term Debt 2019-2026 2.92% 2.73%-13.718% 2.06%-13.718% 126.9 126.8 Total Long-term Debt Outstanding $ 3,980.1 $ 4,033.9 I&M Senior Unsecured Notes 2019-2047 5.20% 3.20%-7.00% 3.20%-7.00% $ 1,809.0 $ 1,512.8 Pollution Control Bonds (a) 2018-2025 (b) 2.02% 1.75%-2.75% 0.74%-4.625% 264.6 225.4 Notes Payable – Nonaffiliated (c) 2017-2022 2.15% 2.03%-2.19% 1.456%-1.81% 188.6 251.4 Spent Nuclear Fuel Obligation (e) 268.6 266.3 Other Long-term Debt 2018-2025 3.03% 2.82%-6.00% 2.15%-6.00% 214.3 215.5 Total Long-term Debt Outstanding $ 2,745.1 $ 2,471.4 OPCo Senior Unsecured Notes 2018-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,591.4 $ 1,590.2 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.3 Securitization Bonds 2018-2019 (d) 2.049% 2.049% 0.958%-2.049% 94.5 140.2 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.1 1.2 Total Long-term Debt Outstanding $ 1,719.3 $ 1,763.9 PSO Senior Unsecured Notes 2019-2046 4.80% 3.05%-6.625% 3.05%-6.625% $ 1,144.1 $ 1,143.2 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2019-2027 2.60% 2.584%-3.00% 1.92%-3.00% 129.8 130.2 Total Long-term Debt Outstanding $ 1,286.5 $ 1,286.0 SWEPCo Senior Unsecured Notes 2017-2045 4.78% 2.75%-6.45% 2.75%-6.45% $ 2,110.7 $ 2,359.2 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 135.1 134.9 Notes Payable – Nonaffiliated (c) 2024-2032 5.20% 4.58%-6.37% 4.58%-6.37% 72.1 75.3 Other Long-term Debt 2017-2023 3.00% 2.925%-4.28% 2.346%-4.28% 124.0 109.7 Total Long-term Debt Outstanding $ 2,441.9 $ 2,679.1 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (f) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2018 $ 1,753.7 $ 266.1 $ 50.0 $ 249.2 $ 474.7 $ 397.0 $ 0.5 $ 3.7 2019 2,307.9 501.1 85.0 305.4 535.2 48.0 375.5 457.2 2020 1,322.0 377.7 — 90.3 26.4 0.1 13.2 118.7 2021 1,352.9 66.2 50.0 393.0 49.9 500.1 250.5 3.7 2022 1,318.4 493.1 104.0 26.0 3.5 0.1 0.5 278.7 After 2022 13,265.7 1,970.5 2,286.0 2,951.0 1,673.9 782.9 652.5 1,594.9 Principal Amount 21,320.6 3,674.7 2,575.0 4,014.9 2,763.6 1,728.2 1,292.7 2,456.9 Unamortized Discount, Net and Debt Issuance Costs (147.3 ) (25.4 ) (24.6 ) (34.8 ) (18.5 ) (8.9 ) (6.2 ) (15.0 ) Total Long-term Debt Outstanding $ 21,173.3 $ 3,649.3 $ 2,550.4 $ 3,980.1 $ 2,745.1 $ 1,719.3 $ 1,286.5 $ 2,441.9
Dividend Payment Restrictions	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Restricted Retained Earnings $ 1,375.6 (a) $ 219.6 $ — $ — $ 416.2 $ — $ 173.5 $ 470.6 (a) Includes the restrictions of consolidated and unconsolidated subsidiaries.
Lines of Credit and Short-term Debt	December 31, 2017 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 718.0 1.22 % $ 673.0 0.70 % AEP Commercial Paper 898.6 1.85 % 1,040.0 1.02 % SWEPCo Notes Payable 22.0 2.92 % — — % Total Short-term Debt $ 1,638.6 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2017 : Maximum Average Net Loans to 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 December 31, 2017 Limit (in millions) AEP Texas $ 296.0 $ 451.7 $ 194.8 $ 264.6 $ 103.5 $ 400.0 AEPTCo 467.2 268.0 180.5 119.8 109.2 795.0 (a) APCo 231.5 160.7 144.3 30.0 (162.5 ) 600.0 I&M 367.4 12.6 204.9 12.6 (199.2 ) 500.0 OPCo 280.6 56.2 137.0 27.9 (87.8 ) 400.0 PSO 185.2 — 119.3 — (149.6 ) 300.0 SWEPCo 187.5 178.6 95.5 169.5 (118.7 ) 350.0 Year Ended December 31, 2016 : Maximum Average Net Loans to 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 December 31, 2016 Limit (in millions) AEP Texas $ 176.9 $ 138.9 $ 87.5 $ 79.8 $ (174.5 ) $ 400.0 AEPTCo 363.4 82.0 153.7 — 14.6 49.8 795.0 (a) APCo 286.9 25.7 148.0 24.8 (55.5 ) 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Nonutility Money Pool Activity	Year Ended December 31, 2017 : Maximum Maximum Average Average Net Loans to Borrowings from Loans to the Borrowings from Loans to the the Nonutility the Nonutility Nonutility the Nonutility Nonutility Money Pool as of Company Money Pool Money Pool Money Pool Money Pool December 31, 2017 (in millions) AEP Texas $ — $ 8.6 $ — $ 8.3 $ 8.4 SWEPCo — 2.0 — 2.0 2.0 Year Ended December 31, 2016 : Maximum Maximum Average Average Net Loans to Borrowings from Loans to the Borrowings from Loans to the the Nonutility the Nonutility Nonutility the Nonutility Nonutility Money Pool as of Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 (in millions) AEP Texas (a) $ 12.5 $ 27.0 $ 12.0 $ 12.3 $ 8.6 SWEPCo — 2.0 — 2.0 2.0 (a) Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information.
Direct Borrowing Activity	Year Ended December 31, 2017 : Borrowings from Loans to Authorized Maximum Maximum Average Average AEP as of AEP as of Short-term Borrowings Loans Borrowings Loans December 31, December 31, Borrowing Company from AEP to AEP from AEP to AEP 2017 2017 Limit (in millions) AEP Texas $ — $ — $ — $ — $ — $ — $ — AEPTCo 4.1 151.9 1.1 39.3 1.1 22.5 75.0 (b) Year Ended December 31, 2016 : Borrowings from Loans to Authorized Maximum Maximum Average Average AEP as of AEP as of Short-term Borrowings Loans Borrowings Loans December 31, December 31, Borrowing Company from AEP to AEP from AEP to AEP 2016 2016 Limit (in millions) AEP Texas (a) $ 55.0 $ 5.0 $ 42.5 $ 5.0 $ — $ 5.0 $ — AEPTCo 5.6 170.4 1.0 35.7 1.0 14.2 75.0 (b) (a) Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information. (b) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2017 2016 2015 Maximum Interest Rate 1.85 % 1.02 % 0.87 % Minimum Interest Rate 0.92 % 0.69 % 0.37 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2017 2016 2015 2017 2016 2015 AEP Texas 1.29 % 0.88 % 0.46 % 1.26 % 0.72 % 0.52 % AEPTCo 1.36 % 0.85 % 0.46 % 1.27 % 0.83 % 0.49 % APCo 1.28 % 0.80 % 0.53 % 1.29 % 0.82 % 0.47 % I&M 1.27 % 0.80 % 0.49 % 1.29 % 0.80 % 0.48 % OPCo 1.37 % 0.85 % — % 0.98 % 0.74 % 0.48 % PSO 1.32 % 0.96 % 0.49 % — % 0.83 % 0.48 % SWEPCo 1.28 % 0.79 % 0.53 % 0.98 % 0.90 % 0.48 %
Maximum, Minimum and Average Interest Rates for Funds Borrowed from and Loaned to the Nonutility Money Pool	Year Ended December 31, 2017 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas — % — % 1.85 % — % — % 1.32 % SWEPCo — % — % 1.85 % — % — % 1.32 % Year Ended December 31, 2016 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas 1.11 % 0.97 % 1.02 % 0.75 % 1.00 % 0.86 % SWEPCo — % — % 1.02 % 0.69 % — % 0.82 % Year Ended December 31, 2015 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas 1.14 % 0.64 % — % — % 0.76 % — % SWEPCo — % — % 0.87 % 0.37 % — % 0.48 %
Maximum Minimum and Average Interest Rates for Funds Borrowed from and Loaned to AEP	Year Ended December 31, 2017 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Company AEP AEP AEP AEP AEP AEP AEP Texas — % — % — % — % — % — % AEPTCo 1.85 % 0.92 % 1.85 % 0.92 % 1.33 % 1.36 % Year Ended December 31, 2016 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Company AEP AEP AEP AEP AEP AEP AEP Texas 0.98 % 0.69 % 1.02 % 0.99 % 0.83 % 1.00 % AEPTCo 1.02 % 0.69 % 1.02 % 0.69 % 0.83 % 0.87 % Year Ended December 31, 2015 : Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Company AEP AEP AEP AEP AEP AEP AEP Texas 0.87 % 0.37 % — % — % 0.48 % — % AEPTCo 0.87 % 0.37 % 0.87 % 0.37 % 0.48 % 0.47 %
Comparative Accounts Receivable Information	Years Ended December 31, 2017 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.22 % 0.70 % 0.30 % Net Uncollectible Accounts Receivable Written Off $ 23.4 $ 23.7 $ 34.1
Customer Accounts Receivable Managed Portfolio	December 31, 2017 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 925.5 $ 945.0 Short-term – Securitized Debt of Receivables 718.0 673.0 Delinquent Securitized Accounts Receivable 41.1 42.7 Bad Debt Reserves Related to Securitization 28.7 27.7 Unbilled Receivables Related to Securitization 303.2 322.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2017 2016 (in millions) APCo $ 136.2 $ 142.0 I&M 136.5 136.7 OPCo 367.4 388.3 PSO 115.1 110.4 SWEPCo 138.2 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 5.6 $ 6.7 $ 7.6 I&M 6.7 7.1 8.4 OPCo 21.7 28.9 30.7 PSO 7.0 6.2 5.8 SWEPCo 7.2 6.9 7.0
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 1,372.8 $ 1,412.5 $ 1,453.8 I&M 1,612.9 1,596.2 1,553.0 OPCo 2,339.0 2,633.0 2,569.4 PSO 1,337.0 1,269.3 1,326.1 SWEPCo 1,563.4 1,531.7 1,597.8

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Performance Units and Reinvested Dividends on Outstanding Performance Units	Years Ended December 31, Performance Units 2017 2016 2015 Awarded Units (in thousands) (a) 590.7 597.4 575.0 Weighted Average Unit Fair Value at Grant Date $ 69.78 $ 62.77 $ 59.19 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2017 2016 2015 Awarded Units (in thousands) (c) 74.6 89.2 103.6 Weighted Average Fair Value at Grant Date $ 72.35 $ 63.83 $ 54.35 Vesting Period (in years) (b) (b) (b) (a) Awarded units in 2017 are mezzanine equity awards and awarded units in 2016 and 2015 are liability awards. (b) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends. (c) In 2017 the awarded dividends were a mix of equity awards and liability awards, while they were all liability awards in 2016 and 2015.
Summary of Performance Scores and Performance Units Earned	Years Ended December 31, Performance Units 2017 2016 2015 Certified Performance Score 164.8 % 163.9 % 176.3 % Performance Units Earned 956,055 1,111,966 1,202,107 Performance Units Mandatorily Deferred as AEP Career Shares 20,213 9,963 41,707 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 47,177 51,684 54,074 Performance Units to be Settled in Cash 888,665 1,050,319 1,106,326
Summary of Cash Payouts for Performance Units and Career Shares	Years Ended December 31, Performance Units and AEP Career Shares 2017 2016 2015 (in millions) Cash Settlements for Performance Units $ 64.9 $ 62.7 $ 48.1 Cash Settlements for Career Share Distributions — 9.1 3.0 AEP Common Stock Settlements for Career Share Distributions 0.4 — —
Summary of Units Awarded and Fair Value of Restricted Stock Units	Years Ended December 31, Restricted Stock Units 2017 2016 2015 Awarded Units (in thousands) 255.8 242.0 397.5 Weighted Average Grant Date Fair Value $ 65.26 $ 62.88 $ 58.56
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	Years Ended December 31, Restricted Stock Units 2017 2016 2015 (in millions) Fair Value of Restricted Stock Units Vested $ 16.1 $ 16.4 $ 18.3 Intrinsic Value of Restricted Stock Units Vested (a) 20.0 21.0 24.2 (a) Intrinsic value is calculated as market price at exercise date.
Status of Nonvested Restricted Shares and Restricted Stock Units	Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2017 603.6 $ 57.54 Granted 255.8 65.26 Vested (295.1 ) 54.72 Forfeited (34.7 ) 61.53 Nonvested as of December 31, 2017 529.6 62.13
Stock Unit Accumulation Plan for Non-employee Directors	Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2017 2016 2015 Awarded Units (in thousands) 14.8 19.1 24.9 Weighted Average Grant Date Fair Value $ 70.79 $ 64.96 $ 55.46
Compensation Cost and Actual Tax Benefit Realized for Tax Deductions from Compensation Cost for Share-based Payment Arrangements	Years Ended December 31, Share-based Compensation Plans 2017 2016 2015 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 79.5 $ 66.5 $ 63.8 Actual Tax Benefit (b) 18.9 23.3 22.3 Total Compensation Cost Capitalized 26.4 20.8 20.3 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income. (b) In December 2017, Tax Reform modified Section 162(m) of the Internal Revenue Code. Beginning after 2017, AEP can no longer deduct compensation expense in excess of $1 million for certain named executive officers. This will reduce the tax benefit going forward.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Affiliated Revenues	Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2017 Direct Sales to East Affiliates $ — $ — $ 130.4 $ — $ — $ — $ — Direct Sales to West Affiliates — — — 3.8 — — — Auction Sales to OPCo (a) — — 1.0 — — — — Direct Sales to AEPEP 63.6 — — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales — 572.0 34.1 (4.4 ) 6.2 — 24.2 Other Revenues 2.1 8.5 6.5 2.4 18.2 4.3 1.9 Total Affiliated Revenues $ 65.7 $ 580.5 $ 172.0 $ 1.8 $ 24.4 $ 4.3 $ 25.9 Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ — $ — $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — — — 3.7 Auction Sales to OPCo (a) — — 9.2 12.0 — — — Direct Sales to AEPEP 73.9 — — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales — 366.1 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 1.8 — 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 75.7 $ 366.1 $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ — $ — $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) — — 10.6 17.1 — — — Direct Sales to AEPEP 76.9 — — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales — 225.6 0.7 8.4 35.5 0.2 15.2 Other Revenues 1.6 — 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 78.5 $ 225.6 $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 (a) Refer to the Ohio Auctions section below for further information regarding these amounts.
Affiliated Purchases	Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2017 Auction Purchases from AEPEP (a) $ — $ 96.5 $ — Auction Purchases from AEP Energy (a) — 5.5 — Auction Purchases from AEPSC (a) — 6.5 — Direct Purchases from AEGCo 223.9 — — Total Affiliated Purchases $ 223.9 $ 108.5 $ — Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates $ — $ — $ 3.7 Auction Purchases from AEPEP (a) — 110.1 — Auction Purchases from AEP Energy (a) — 7.7 — Auction Purchases from AEPSC (a) — 24.1 — Direct Purchases from AEGCo 228.6 — — Total Affiliated Purchases $ 228.6 $ 141.9 $ 3.7 Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2015 Direct Purchases from AGR (b) $ — $ 269.2 $ — Auction Purchases from AEPEP (a) — 225.2 — Auction Purchases from AEPSC (a) — 32.7 — Direct Purchases from AEGCo 232.1 — — Total Affiliated Purchases $ 232.1 $ 527.1 $ — (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Amount excludes $31 million in 2015 which is now presented as Generation Deferrals on the Statement of Income.
Transmission Agreement	Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 158.2 $ 103.2 $ 92.7 I&M 103.8 53.0 38.0 OPCo 248.6 143.6 81.0
Transmission Coordination Agreement	Years Ended December 31, Company 2017 2016 2015 (in millions) PSO $ 56.0 $ 19.6 $ 15.0 SWEPCo 6.6 (19.6 ) (15.0 )
Joint License Agreement [Table Text Block]	Years Ended December 31, Billing Company 2017 2016 2015 (in millions) I&M $ 1.4 $ 0.8 $ 0.6 KPCo 0.2 0.1 — OPCo 2.4 2.3 2.0 PSO 0.3 0.2 0.3
Coal Transloading	Years Ended December 31, Company 2017 2016 2015 (in millions) I&M $ 10.2 $ 12.8 $ 15.8
Railcar Maintenance	Years Ended December 31, Company 2017 2016 2015 (in millions) I&M $ 1.3 $ 1.7 $ 2.0 PSO 0.5 0.6 0.2 SWEPCo 3.5 3.3 2.8
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2017 2016 2015 (in millions) AEGCo $ 15.3 $ 14.8 $ 16.1 AGR 0.1 0.3 4.9 APCo 37.2 36.9 37.7 KPCo 5.0 5.3 4.6 WPCo 5.0 4.8 — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — — 15.5
Central Machine Shop	Years Ended December 31, Company 2017 2016 2015 (in millions) AEGCo $ — $ — $ 0.1 AGR 1.2 2.0 2.7 I&M 2.7 2.9 2.5 KPCo 1.8 1.5 1.3 PSO 1.1 0.5 0.2 SWEPCo 0.8 0.9 0.8
Related Party Sales of Property	Sales Years Ended December 31, Company 2017 2016 2015 (in millions) AEP Texas $ 0.2 $ 0.3 $ 0.6 AEPTCo — — 0.2 APCo 3.5 4.5 9.4 I&M 5.0 5.2 3.0 OPCo 2.9 1.9 2.4 PSO 1.5 7.5 7.1 SWEPCo 0.5 1.0 0.8
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2017 2016 2015 (in millions) AEP Texas $ 0.4 $ 0.7 $ 0.9 AEPTCo 9.1 6.5 0.4 APCo 0.9 1.5 8.6 I&M 3.5 2.7 8.1 OPCo 1.6 1.7 2.1 PSO 0.2 3.2 0.6 SWEPCo 0.4 6.5 7.4

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2017
Consolidated Assets And Liabilities Of Variable Interest Entities	American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2017 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel AEP Texas Transition Funding OPCo APCo (in millions) ASSETS Current Assets $ 56.3 $ 102.5 $ 191.7 $ 28.7 $ 22.3 Net Property, Plant and Equipment 113.2 179.9 — — — Other Noncurrent Assets 90.2 86.3 923.5 (a) 71.0 (b) 285.6 (c) Total Assets $ 259.7 $ 368.7 $ 1,115.2 $ 99.7 $ 307.9 LIABILITIES AND EQUITY Current Liabilities $ 49.1 $ 96.5 $ 260.9 $ 47.9 $ 27.6 Noncurrent Liabilities 211.0 272.2 836.1 50.5 278.4 Equity (0.4 ) — 18.2 1.3 1.9 Total Liabilities and Equity $ 259.7 $ 368.7 $ 1,115.2 $ 99.7 $ 307.9 (a) Includes an intercompany item eliminated in consolidation of $53.9 million . (b) Includes an intercompany item eliminated in consolidation of $33.3 million . (c) Includes an intercompany item eliminated in consolidation of $3.4 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2017 Other Consolidated VIEs AEP Credit Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 926.3 $ 178.7 $ 17.4 Net Property, Plant and Equipment — — 323.9 Other Noncurrent Assets 6.4 — 3.1 Total Assets $ 932.7 $ 178.7 $ 344.4 LIABILITIES AND EQUITY Current Liabilities $ 872.0 $ 36.4 $ 12.4 Noncurrent Liabilities 0.7 95.2 132.0 Equity 60.0 47.1 200.0 Total Liabilities and Equity $ 932.7 $ 178.7 $ 344.4 American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel AEP Texas Transition Funding OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 184.8 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — — Other Noncurrent Assets 89.8 116.2 1,149.4 (a) 117.1 (b) 309.0 (c) Total Assets $ 262.0 $ 485.6 $ 1,334.2 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 251.9 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 1,064.2 98.6 300.6 Equity 0.4 — 18.1 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 1,334.2 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . (b) Includes an intercompany item eliminated in consolidation of $55 million . (c) Includes an intercompany item eliminated in consolidation of $3.7 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2016 Other Consolidated VIEs AEP Credit Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — 313.0 130.4 Other Noncurrent Assets 10.3 1.1 5.4 9.0 Total Assets $ 956.0 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 97.3 134.4 11.3 Equity 78.0 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 171.7 $ 334.7 $ 139.4
SWEPCo's Investment In DHLC	December 31, 2017 2016 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 11.8 11.8 15.7 15.7 SWEPCo’s Share of Obligations — 144.3 — 91.3 Total Investment in DHLC $ 19.4 $ 163.7 $ 23.3 $ 114.6
AEP's Investment In OVEC	December 31, 2017 2016 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from AEP $ 4.4 $ 4.4 $ 4.4 $ 4.4 AEP’s Ratio of OVEC Debt (a) — 626.3 — 658.3 Total Investment in OVEC $ 4.4 $ 630.7 $ 4.4 $ 662.7 (a) Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt is $226 million , $113.1 million and $287.2 million for the year ended December 31, 2017 and $237.6 million , $118.9 million and $301.8 million for the year-ended December 31, 2016, respectively.
Purchased Power from OVEC	Years Ended December 31, Company 2017 2016 2015 (in millions) APCo $ 101.0 $ 88.0 $ 87.2 I&M 50.5 44.0 43.7 OPCo 128.2 111.7 110.8
AEP's Investment In PATH-WV	December 31, 2017 2016 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.0 ) (2.0 ) (2.3 ) (2.3 ) Total Investment in PATH-WV $ 16.8 $ 16.8 $ 16.5 $ 16.5
Billings from Significant Variable Interest	Years Ended December 31, Company 2017 2016 2015 (in millions) AEP Texas $ 152.6 $ 142.3 $ 132.7 AEPTCo 188.9 131.1 108.4 APCo 268.8 244.2 227.5 I&M 176.0 147.7 139.5 OPCo 195.7 181.1 177.8 PSO 114.7 111.0 107.3 SWEPCo 150.7 147.0 141.4
Carrying Amount and Classification of Variable Interest in Accounts Payable	December 31, 2017 2016 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) AEP Texas $ 24.2 $ 24.2 $ 22.9 $ 22.9 AEPTCo 25.1 25.1 23.0 23.0 APCo 37.0 37.0 36.7 36.7 I&M 26.8 26.8 24.2 24.2 OPCo 27.4 27.4 28.1 28.1 PSO 18.7 18.7 16.0 16.0 SWEPCo 20.8 20.8 21.8 21.8

Property, Plant and Equipment53

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment	December 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 20,406.5 (a) $ — $ — $ 6,446.9 $ 4,445.9 $ — $ 1,577.2 $ 4,624.9 (a) Transmission 18,942.3 3,053.6 5,336.1 3,019.9 1,504.0 2,419.2 858.8 1,679.8 Distribution 19,865.9 3,718.6 — 3,763.8 2,069.3 4,626.4 2,445.1 2,095.8 Other 3,224.8 457.6 130.0 399.5 552.3 485.5 282.0 416.8 CWIP 3,972.6 (a) 834.4 1,312.7 483.0 460.2 410.1 111.3 220.7 (a) Less: Accumulated Depreciation 16,906.7 1,399.4 170.4 3,891.1 3,011.7 2,183.9 1,393.6 2,520.5 Total Regulated Property, Plant and Equipment - Net 49,505.4 6,664.8 6,608.4 10,222.0 6,020.0 5,757.3 3,880.8 6,517.5 Nonregulated Property, Plant and Equipment - Net 756.1 160.3 1.4 23.1 30.4 9.5 5.4 114.5 Total Property, Plant and Equipment - Net $ 50,261.5 $ 6,825.1 $ 6,609.8 $ 10,245.1 $ 6,050.4 $ 5,766.8 $ 3,886.2 $ 6,632.0 December 31, 2016 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (a) $ — $ — $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (a) Transmission 16,658.6 2,623.6 3,973.5 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,527.2 — 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 432.1 98.3 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (a) 385.0 981.3 390.3 654.2 221.5 148.2 113.7 (a) Less: Accumulated Depreciation 16,101.5 1,354.4 99.6 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 5,613.5 4,953.5 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 167.2 1.1 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (b) $ 5,780.7 $ 4,954.6 $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Depreciation, Depletion and Amortization - Regulated	AEP 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.3% - 3.7% 20 - 132 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 Transmission 1.6% - 2.7% 15 - 100 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 Distribution 2.7% - 3.7% 5 - 156 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 Other 2.3% - 9.2% 5 - 84 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 AEP Texas 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 1.7% 45 - 81 1.8% 45 - 81 1.8% 45 - 81 Distribution 3.6% 7 - 70 3.3% 7 - 70 3.3% 7 - 70 Other 8.7% 5 - 50 8.3% 5 - 50 9.7% 5 - 50 AEPTCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 1.7% 20 - 100 1.6% 20 - 100 1.4% 20 - 75 APCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 112 3.1% 35 - 121 3.1% 35 - 121 Transmission 1.6% 15 - 68 1.5% 15 - 68 1.6% 15 - 68 Distribution 3.7% 10 - 57 3.7% 10 - 57 3.6% 10 - 57 Other 6.5% 5 - 55 6.0% 5 - 55 8.3% 5 - 55 I&M 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 20 - 132 2.4% 59 - 132 2.5% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.7% 10 - 70 2.8% 10 - 70 2.8% 10 - 70 Other 8.4% 5 - 45 8.6% 5 - 45 11.8% 5 - 45 OPCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 5 - 57 2.8% 7 - 57 2.8% 7 - 57 Other 6.2% 5 - 50 5.9% 5 - 50 7.2% 5 - 50 PSO 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 2.4% 35 - 85 1.7% 35 - 70 Transmission 2.2% 45 - 100 2.2% 45 - 100 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.7% 27 - 156 2.5% 7 - 65 Other 7.4% 5 - 84 6.4% 5 - 84 4.6% 5 - 40 SWEPCo 2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.3% 40 - 70 2.1% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 73 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.7% 25 - 70 2.6% 25 - 65 2.6% 25 - 65 Other 7.2% 5 - 55 6.8% 5 - 51 5.5% 5 - 51
Depreciation, Depletion and Amortization - Unregulated	2017 2016 2015 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% - 5.1% 15 - 66 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 Transmission 0.2% 40 2.3% 43 - 55 2.3% 43 - 55 Distribution 2.3% 40 1.3% 40 - 50 —% 0 - 0 Other 12.1% 5 - 50 (a) 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2016 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2017 (in millions) AEP (a)(b)(c)(d) $ 1,934.9 $ 90.9 $ 2.4 $ (104.5 ) $ 82.0 $ 2,005.7 AEP Texas (a)(d) 25.5 1.2 — (0.1 ) 0.1 26.7 APCo (a)(d) 127.1 7.0 — (21.7 ) 12.6 125.0 I&M (a)(b)(d) 1,258.1 55.9 — (0.1 ) 7.9 1,321.8 OPCo (d) 1.7 0.1 — (0.1 ) — 1.7 PSO (a)(d) 53.4 3.1 — (0.5 ) (2.0 ) 54.0 SWEPCo (a)(c)(d) 156.5 8.3 — (0.3 ) 4.7 169.2 Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (a)(b)(c)(d) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (e) $ 66.4 $ 1,934.9 AEP Texas (a)(d) 24.0 1.1 — (0.1 ) 0.5 25.5 APCo (a)(d) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (a)(b)(d) 1,253.8 55.6 — (62.6 ) (e) 11.3 1,258.1 OPCo (d) 1.4 0.1 0.2 — — 1.7 PSO (a)(d) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (a)(c)(d) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.30 billion and $1.24 billion as of December 31, 2017 and 2016 , respectively. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance For Equity Funds Used During Construction	Years Ended December 31, Company 2017 2016 2015 (in millions) AEP $ 93.7 $ 113.2 $ 131.9 AEP Texas 6.8 9.2 6.7 AEPTCo 52.3 52.3 53.0 APCo 9.2 11.7 13.8 I&M 11.1 15.3 11.6 OPCo 6.4 6.0 8.8 PSO 0.5 6.2 8.8 SWEPCo 2.4 11.0 26.4
Allowance For Borrowed Funds Used During Construction	Years Ended December 31, Company 2017 2016 2015 (in millions) AEP $ 48.6 $ 51.7 $ 61.3 AEP Texas 6.8 5.9 4.5 AEPTCo 20.2 15.6 17.7 APCo 5.3 6.3 6.9 I&M 6.7 7.2 5.0 OPCo 3.8 3.3 4.8 PSO 1.1 3.4 5.0 SWEPCo 2.1 6.9 14.8
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2017 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a)(k)(l) Coal 83.5 % $ 2.1 $ 4.2 $ 0.1 J.M. Stuart Generating Station (b)(k) Coal 26.0 % — — — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 343.1 5.3 214.2 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 589.8 7.8 406.3 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 456.4 1.9 254.6 Turk Generating Plant (j)(n) Coal 73.3 % 1,580.4 3.2 166.6 Transmission NA (d) 62.7 0.3 46.1 Total $ 3,399.3 $ 31.6 $ 1,169.5 AEP Texas Oklaunion Generating Station, Unit 1 (h) Coal 54.7 % $ 350.7 $ 1.3 $ 194.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 1,093.9 $ 28.2 $ 562.6 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.7 $ 0.6 $ 60.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 343.1 $ 5.3 $ 214.2 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 589.8 7.8 406.3 Turk Generating Plant (j)(n) Coal 73.3 % 1,580.4 3.2 166.6 Total $ 2,878.1 $ 25.2 $ 868.7 Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a)(k)(l) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b)(k) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c)(k)(m) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 AEP Texas Oklaunion Generating Station, Unit 1 (h) Coal 54.7 % $ 349.6 $ 0.9 $ 186.5 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 (a) Operated by AGR. (b) Operated by Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. J.M. Stuart Generating Station and Wm. H. Zimmer Generating Station were impaired as of November 30, 2016. See the “Impairments” section of Note 7 . (l) In accordance with the Asset Purchase Agreement between AGR and Dynegy Corporation dated February 2017, AGR acquired Dynegy Corporation’s 40% ownership interest in Conesville Generating Station, Unit 4. Subsequent to this transaction, AGR’s ownership percentage in Conesville Generating Station, Unit 4 is 83.5% . (m) In accordance with the Asset Purchase Agreement between AGR and Dynegy Corporation dated February 2017, Dynegy Corporation acquired AGR’s 25.4% ownership interest in Wm. H. Zimmer Generating Station. Subsequent to this transaction, AGR has no ownership interest in Wm. H. Zimmer Generating Station. See the “Dispositions” section of Note 7 . (n) In December 2017, SWEPCo recorded a $15 million pretax impairment related to the Louisiana jurisdictional share of Turk Plant. Amount reflects the impact of the impairment. See the “Impairments” section of Note 7 . NA Not applicable.

Unaudited Quarterly Financial54

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Quarterly Financial Information	2017 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 592.2 $ 375.0 $ 544.7 $ 400.7 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.20 0.76 1.11 0.81 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.20 0.76 1.10 0.81 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 (a) Relates to impairments for certain merchant generation assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). Quarterly Periods Ended: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2017 Total Revenues $ 3,933.3 $ 343.6 $ 152.7 $ 792.8 $ 560.5 $ 746.1 $ 304.1 $ 401.3 Operating Income 1,097.1 83.2 90.4 220.2 118.7 150.7 20.8 53.7 Net Income 594.2 33.3 57.0 110.6 68.4 86.2 4.8 17.3 Earnings Attributable to Common Shareholders 592.2 NA NA NA NA NA NA 16.3 June 30, 2017 Total Revenues $ 3,576.5 $ 389.5 $ 229.4 $ 675.3 $ 467.3 $ 663.9 $ 344.7 $ 424.7 Operating Income 744.7 109.7 165.4 127.4 35.2 119.6 46.1 75.0 Net Income 376.2 49.0 107.4 52.1 10.5 62.3 20.4 25.1 Earnings Attributable to Common Shareholders 375.0 NA NA NA NA NA NA 24.5 September 30, 2017 Total Revenues $ 4,104.7 $ 431.2 $ 167.3 $ 719.3 $ 557.7 $ 742.0 $ 442.8 $ 517.6 Operating Income 986.5 129.7 95.1 173.0 115.1 154.5 86.8 137.0 Net Income 556.7 64.3 59.9 86.0 64.9 82.6 46.2 84.1 Earnings Attributable to Common Shareholders 544.7 NA NA NA NA NA NA 73.1 December 31, 2017 Total Revenues $ 3,810.4 $ 374.1 $ 173.8 $ 746.8 $ 535.7 $ 731.9 $ 335.6 $ 436.3 Operating Income 742.2 97.1 96.9 174.9 84.3 145.4 21.2 42.0 Net Income 401.8 163.9 61.8 82.6 42.9 92.8 0.6 11.0 Earnings Attributable to Common Shareholders 400.7 NA NA NA NA NA NA 10.8 NA Not applicable. Quarterly Periods Ended: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 330.5 $ 79.6 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 82.4 34.8 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 35.0 — — — — — — Income (Loss) from Discontinued Operations, Net of Tax — (1.3 ) (c) — — — — — — Net Income 503.1 33.7 25.8 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 365.0 $ 153.1 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 103.4 108.1 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 49.7 — — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) (0.7 ) (c) — — — — — — Net Income 503.9 49.0 74.8 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 403.9 $ 125.3 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 112.4 76.4 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) 55.5 — — — — — — Income (Loss) from Discontinued Operations, Net of Tax — (47.4 ) (c) — — — — — — Net Income (Loss) (764.2 ) (b) 8.1 52.4 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 362.0 $ 120.0 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 81.4 60.8 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 55.2 — — — — — — Income from Discontinued Operations, Net of Tax — 0.6 (c) — — — — — — Net Income 375.2 55.8 39.7 65.3 38.5 37.5 2.6 16.5 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for certain merchant generation assets (see Note 7 ). (c) Includes the transfer of the Wind Farms (see Note 7 ).

Goodwill and Other Intangible55

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Changes in Carrying Amount of Goodwill	Corporate and Other Generation & Marketing AEP Consolidated (in millions) Balance as of December 31, 2015 $ 37.1 $ 15.4 $ 52.5 Impairment Losses — — — Balance as of December 31, 2016 37.1 15.4 52.5 Impairment Losses — — — Balance as of December 31, 2017 $ 37.1 $ 15.4 $ 52.5
Amortization Life, Gross Carrying Amount and Accumulated Amortization by Major Asset Class	December 31, 2016 Amortization Life Gross Carrying Amount Accumulated Amortization (in years) (in millions) Acquired Customer Contracts 5 $ 58.3 $ 58.3

Organization and Summary of S56

Organization and Summary of Significant Accounting Policies (Details) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2017USD ($)$ / shares		Sep. 30, 2017$ / shares	[3]	Jun. 30, 2017$ / shares	[3]	Mar. 31, 2017$ / shares	[3]	Dec. 31, 2016USD ($)$ / shares		Sep. 30, 2016USD ($)$ / shares		Jun. 30, 2016USD ($)$ / shares		Mar. 31, 2016USD ($)$ / shares		Dec. 31, 2017USD ($)$ / sharesshares		Dec. 31, 2016USD ($)$ / sharesshares		Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 214.6								$ 210.5								$ 214.6		$ 210.5
Restricted Cash	198								193								198		193
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Including Disposal Group and Discontinued Operations	412.6								403.5								412.6		403.5		$ 426.9	$ 421.6
Assets
Current Assets	4,253.1								6,033.9								4,253.1		6,033.9
Property, Plant and Equipment, Net	50,261.5								45,639.3	[1]							50,261.5		45,639.3	[1]
Other Noncurrent Assets	10,214.5								11,794.5								10,214.5		11,794.5
TOTAL ASSETS	64,729.1								63,467.7								64,729.1		63,467.7		61,683.1
Liabilities and Equity
Long-term Debt	21,173.3								20,256.4								21,173.3		20,256.4
Other Current Liabilities	1,033.2								1,302.8								1,033.2		1,302.8
Other Liabilities, Noncurrent	830.9								774.6								830.9		774.6
Equity	18,313.6								17,420.1								18,313.6		17,420.1		17,904.9	16,824.5
TOTAL LIABILITIES AND EQUITY	$ 64,729.1								63,467.7								64,729.1		63,467.7
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									$ 375.2		$ (764.2)	[2]	$ 506.4		$ 503.1		1,928.9		620.5		1,768.6
Net Income (Loss) Attributable to Noncontrolling Interests																	16.3		7.1		5.2
Income (Loss) from Continuing Operations Attributable to Parent																	$ 1,912.6		$ 613.4		$ 1,763.4
Weighted Average Number of Basic AEP Common Shares Outstanding | shares																	491,814,651		491,495,458		490,340,522
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares	$ 0.81	[3]	$ 1.11		$ 0.76		$ 1.20		$ 0.76	[3]	$ (1.56)	[3],[4]	$ 1.03	[3]	$ 1.02	[3]	$ 3.89		$ 1.25		$ 3.59
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding | shares																	492,611,067		491,662,007		490,574,568
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares	$ 0.81	[3]	$ 1.10		$ 0.76		$ 1.20		$ 0.76	[3]	$ (1.56)	[3],[4]	$ 1.03	[3]	$ 1.02	[3]	$ 3.88		$ 1.25		$ 3.59
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	$ 1,709.1		$ 1,688.5		$ 1,674.3
Amortization of Certain Securitized Assets																	275.9		254.6		318.9
Amortization of Regulatory Assets and Liabilities																	12.2		19.2		16.5
Utilities Operating Expense, Depreciation and Amortization																	1,997.2		1,962.3		2,009.7
Cash Paid (Received) for:
Interest Paid, Net																	858.3		848.5		857.2
Income Taxes Paid, Net																	(1.1)		29.5		120.2
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	60.7		86.1		150.2
Construction Expenditures Included in Current Liabilities as of December 31,																	1,330.8		858		741.4
Construction Expenditures Included in Noncurrent Liabilities as of December 31,																	71.8		0		51.6
Construction Expenditures Included in Noncurrent Assets as of December 31,																	0		0		10.5
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,																	0		2.1		37.9
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage																	2.6		0.7		2.2
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	3,854.1		2,594.9		3,436.6
Repayments of Long-term Debt																	$ 3,087.9		1,794.9		2,397.9
Number of Equity Method Investments	2																2
Equity Method Investment	$ 812.3								$ 809.4								$ 812.3		809.4
Income (Loss) from Equity Method Investment																	$ 82.4		$ 71.2		$ 65.3
Antidilutive Shares Outstanding | shares																	0		0		0
ETT [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%																50.00%
Equity Method Investment	$ 664																$ 664
Income (Loss) from Equity Method Investment																	$ 82
ETT [Member] | Berkshire Hathaway [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%																50.00%
ETT [Member] | AEP Transmission Holdco [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Equity Method Investment, Ownership Percentage	49.50%																49.50%
ETT [Member] | AEP Transmission Partner [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Equity Method Investment, Ownership Percentage	0.50%																0.50%
Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
AEP Texas Inc. [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 2								0.6								$ 2		$ 0.6
Restricted Cash	155.2								146.3								155.2		146.3
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Including Disposal Group and Discontinued Operations	157.2								146.9								$ 157.2		146.9		$ 208.4	216.9
Risks and Uncertainties [Abstract]
Percentage of Significant Customers Concentration Risk																	10.00%
Assets
Current Assets	563.8								389.2								$ 563.8		389.2
Property, Plant and Equipment, Net	6,825.1								5,780.7								6,825.1		5,780.7
Other Noncurrent Assets	1,384.7								1,539.2								1,384.7		1,539.2
TOTAL ASSETS	8,773.6								7,709.1								8,773.6		7,709.1
Liabilities and Equity
Long-term Debt	3,649.3								3,217.7								3,649.3		3,217.7
Other Current Liabilities	76.4								94.8								76.4		94.8
Other Liabilities, Noncurrent	63.4								56.3								63.4		56.3
Equity	2,169.9								1,657.1								2,169.9		1,657.1		1,674.7	1,309.4
TOTAL LIABILITIES AND EQUITY	8,773.6								7,709.1								8,773.6		7,709.1
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									55.2		$ 55.5		$ 49.7		$ 35		310.5		195.4		121.7
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	221.1		204		193.3
Amortization of Certain Securitized Assets																	231.4		210.3		275.5
Amortization of Regulatory Assets and Liabilities																	(2.4)		(0.4)		0.1
Utilities Operating Expense, Depreciation and Amortization																	450.1		413.9		468.9
Cash Paid (Received) for:
Interest Paid, Net																	134.6		145.6		144
Income Taxes Paid, Net																	(28.3)		38.2		8.1
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	8.2		7.1		6.1
Construction Expenditures Included in Current Liabilities as of December 31,																	325.7		100.1		72.8
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	749.6		199.2		370.1
Repayments of Long-term Debt																	323.1		428.7		273.7
AEP Texas Inc. [Member] | Pension Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 3.6								4.7								$ 3.6		4.7
AEP Texas Inc. [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
AEP Texas Inc. [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
AEP Texas Inc. [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
AEP Texas Inc. [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
AEP Texas Inc. [Member] | Other Postretirement Benefit Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 0								0								$ 0		0
AEP Texas Inc. [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
AEP Texas Inc. [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
AEP Texas Inc. [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
AEP Transmission Co [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 0								0								$ 0		0		0	0
Assets
Current Assets	327.7								178.8								327.7		178.8
Property, Plant and Equipment, Net	6,609.8								4,954.6								6,609.8		4,954.6
Other Noncurrent Assets	130.6								216.4								130.6		216.4
TOTAL ASSETS	7,068.1								5,349.8								7,068.1		5,349.8		4,156.5
Liabilities and Equity
Long-term Debt	2,550.4								1,932								2,550.4		1,932
Other Current Liabilities	4.1								10.9								4.1		10.9
Other Liabilities, Noncurrent	30.7								4								30.7		4
TOTAL LIABILITIES AND EQUITY	7,068.1								5,349.8								7,068.1		5,349.8
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									0		0		0		0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	97.1		65.9		42.4
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	0		0		0
Utilities Operating Expense, Depreciation and Amortization																	97.1		65.9		42.4
Cash Paid (Received) for:
Interest Paid, Net																	61.2		42		32.5
Income Taxes Paid, Net																	(107.3)		(235.1)		(11.2)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	0.2		0		0
Construction Expenditures Included in Current Liabilities as of December 31,																	473.7		298.3		208
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	617.6		686.9		449
Repayments of Long-term Debt																	0		300		0
Appalachian Power Co [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	2.9								2.7								2.9		2.7
Restricted Cash	16.3								15.8								16.3		15.8
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	19.2								18.5								19.2		18.5		17.6	18.2
Assets
Current Assets	636.2								591.7								636.2		591.7
Property, Plant and Equipment, Net	10,245.1								9,825.8								10,245.1		9,825.8
Other Noncurrent Assets	1,047.3								1,559.7								1,047.3		1,559.7
TOTAL ASSETS	11,928.6								11,977.2								11,928.6		11,977.2
Liabilities and Equity
Long-term Debt	3,980.1								4,033.9								3,980.1		4,033.9
Other Current Liabilities	109								129.5								109		129.5
Other Liabilities, Noncurrent	74.7								64.5								74.7		64.5
Equity	3,804.5								3,583.5								3,804.5		3,583.5		3,475	3,366.9
TOTAL LIABILITIES AND EQUITY	$ 11,928.6								11,977.2								11,928.6		11,977.2
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									0		0		0		0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	407.6		387.6		385.6
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	0.3		0.9		3.2
Utilities Operating Expense, Depreciation and Amortization																	407.9		388.5		388.8
Cash Paid (Received) for:
Interest Paid, Net																	183.6		181.8		196.7
Income Taxes Paid, Net																	31.2		22.1		30.4
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	3.5		6.1		31.8
Construction Expenditures Included in Current Liabilities as of December 31,																	126.3		151.6		90.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	320.9		314		726.3
Repayments of Long-term Debt																	$ 377.9		213.6		672.6
Appalachian Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
Indiana Michigan Power Co [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 1.3								1.2								$ 1.3		1.2		1.1	1
Assets
Current Assets	434								419.5								434		419.5
Property, Plant and Equipment, Net	6,050.4								5,627.5								6,050.4		5,627.5
Other Noncurrent Assets	3,287.6								3,294.3								3,287.6		3,294.3
TOTAL ASSETS	9,772								9,341.3								9,772		9,341.3
Liabilities and Equity
Long-term Debt	2,745.1								2,471.4								2,745.1		2,471.4
Other Current Liabilities	106.4								123.4								106.4		123.4
Other Liabilities, Noncurrent	88.5								120.4								88.5		120.4
Equity	2,217.6								2,151.8								2,217.6		2,151.8		2,036.4	1,954
TOTAL LIABILITIES AND EQUITY	9,772								9,341.3								9,772		9,341.3
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									0		0		0		0
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)																	62.6		62.1		78.8
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	203.1		183.9		193.5
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	7.8		7.8		4.9
Utilities Operating Expense, Depreciation and Amortization																	210.9		191.7		198.4
Cash Paid (Received) for:
Interest Paid, Net																	94.8		83.3		84.5
Income Taxes Paid, Net																	(89.9)		(39.5)		21.2
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	7.1		18.2		3
Construction Expenditures Included in Current Liabilities as of December 31,																	88.5		106.2		95.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,																	0		2.1		37.9
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage																	2.6		0.7		2.2
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	530.1		569.4		310.7
Repayments of Long-term Debt																	260.7		100.2		332.1
Indiana Michigan Power Co [Member] | Pension Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 1								25.5								$ 1		25.5
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 0								0								$ 0		0
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
Ohio Power Co [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 3.1								3.1								$ 3.1		3.1
Restricted Cash	26.6								27.2								26.6		27.2
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	29.7								30.3								29.7		30.3		30.8	31.6
Assets
Current Assets	397.9								270.9								397.9		270.9
Property, Plant and Equipment, Net	5,766.8								5,325.6								5,766.8		5,325.6
Other Noncurrent Assets	1,097								1,497.4								1,097		1,497.4
TOTAL ASSETS	7,261.7								7,093.9								7,261.7		7,093.9
Liabilities and Equity
Long-term Debt	1,719.3								1,763.9								1,719.3		1,763.9
Other Current Liabilities	165.9								236								165.9		236
Other Liabilities, Noncurrent	46.2								111.7								46.2		111.7
Equity	2,310.3								2,117.5								2,310.3		2,117.5		1,986.6	1,980.2
TOTAL LIABILITIES AND EQUITY	7,261.7								7,093.9								7,261.7		7,093.9
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									0		0		0		0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	200.9		202.3		184.4
Amortization of Certain Securitized Assets																	44.4		44.3		43.3
Amortization of Regulatory Assets and Liabilities																	(19.4)		(8)		(10.2)
Utilities Operating Expense, Depreciation and Amortization																	225.9		238.6		217.5
Cash Paid (Received) for:
Interest Paid, Net																	100		109.9		121.6
Income Taxes Paid, Net																	48.5		220.4		26.1
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	4.5		3.4		2.7
Construction Expenditures Included in Current Liabilities as of December 31,																	87.8		44.6		34.3
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Notes Receivable - Affiliated	32.3								32.3								32.3		32.3
Repayments of Long-term Debt																	46.4		395.9		131.5
Ohio Power Co [Member] | Pension Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 0.4								19.1								$ 0.4		19.1
Ohio Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
Ohio Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
Ohio Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
Ohio Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 0								0								$ 0		0
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
Public Service Co Of Oklahoma [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 1.6								1.5								$ 1.6		1.5		1.4	1.4
Assets
Current Assets	205.3								195.4								205.3		195.4
Property, Plant and Equipment, Net	3,886.2								3,823.2								3,886.2		3,823.2
Other Noncurrent Assets	416.8								360.6								416.8		360.6
TOTAL ASSETS	4,508.3								4,379.2								4,508.3		4,379.2
Liabilities and Equity
Long-term Debt	1,286.5								1,286								1,286.5		1,286
Other Current Liabilities	44.7								47.8								44.7		47.8
Other Liabilities, Noncurrent	22.5								24.8								22.5		24.8
Equity	1,215.3								1,214.1								1,215.3		1,214.1		1,119.9	1,028.2
TOTAL LIABILITIES AND EQUITY	4,508.3								4,379.2								4,508.3		4,379.2
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									0		0		0		0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	131.4		122.6		108.6
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	(1)		7.6		8.9
Utilities Operating Expense, Depreciation and Amortization																	130.4		130.2		117.5
Cash Paid (Received) for:
Interest Paid, Net																	61.5		60.1		54.8
Income Taxes Paid, Net																	(72.6)		(37.7)		7.9
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	2.1		3.1		3.6
Construction Expenditures Included in Current Liabilities as of December 31,																	23.1		33.6		47.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	0		274.2		248.8
Repayments of Long-term Debt																	0.5		275.4		0.4
Public Service Co Of Oklahoma [Member] | Pension Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 2.5								2.1								$ 2.5		2.1
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent	$ 0								0								$ 0		0
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
Southwestern Electric Power Co [Member]
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 1.6								10.3								$ 1.6		10.3		5.2	14.4
Assets
Current Assets	380.4								546								380.4		546
Property, Plant and Equipment, Net	6,632								6,429.5								6,632		6,429.5
Other Noncurrent Assets	330.5								651.1								330.5		651.1
TOTAL ASSETS	7,342.9								7,626.6								7,342.9		7,626.6
Liabilities and Equity
Long-term Debt	2,441.9								2,679.1								2,441.9		2,679.1
Other Current Liabilities	78.7								83.9								78.7		83.9
Other Liabilities, Noncurrent	19.9								9.7								19.9		9.7
Equity	2,234.5								2,215.2								2,234.5		2,215.2		2,169.7	$ 2,097.2
TOTAL LIABILITIES AND EQUITY	$ 7,342.9								7,626.6								7,342.9		7,626.6
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest									$ 0		$ 0		$ 0		$ 0
Net Income (Loss) Attributable to Noncontrolling Interests																	12.8		4.1		3.7
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																	217.2		196.6		190.7
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	0.2		(0.1)		1.3
Utilities Operating Expense, Depreciation and Amortization																	217.4		196.5		192
Cash Paid (Received) for:
Interest Paid, Net																	124.4		118		112.6
Income Taxes Paid, Net																	(75.3)		(32)		15.4
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	3.3		5.9		7.4
Construction Expenditures Included in Current Liabilities as of December 31,																	71.2		41.8		92.9
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																	114.6		406.7		445.9
Repayments of Long-term Debt																	353.7		3.3		306.8
Income (Loss) from Equity Method Investment																	$ (3.8)		$ 7.9		$ 3.9
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	25.00%																25.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	59.00%																59.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation	15.00%																15.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	1.00%																1.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation	49.00%																49.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation	2.00%																2.00%
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares | shares																	800,000		200,000		300,000
Dilutive Securities, Effect on Basic Earnings Per Share | $ / shares																	$ (0.01)		$ 0		$ 0
Revenues [Member] | AEP Texas Inc. [Member]
Risks and Uncertainties [Abstract]
Percentage of Significant Customers Concentration Risk																	35.00%	[5]	46.00%		53.00%
Revenues [Member] | AEP Transmission Co [Member]
Risks and Uncertainties [Abstract]
Percentage of Significant Customers Concentration Risk																	80.00%		77.00%		73.00%
Accounts Receivable [Member] | AEP Texas Inc. [Member]
Risks and Uncertainties [Abstract]
Percentage of Significant Customers Concentration Risk																	31.00%	[5]	42.00%		43.00%
Accounts Receivable [Member] | AEP Transmission Co [Member]
Risks and Uncertainties [Abstract]
Percentage of Significant Customers Concentration Risk																	82.00%		86.00%		77.00%
[1]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[2]	Includes impairments for certain merchant generation assets (see Note 7).
[3]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[4]	Relates to impairments for certain merchant generation assets (see Note 7).
[5]	Just Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer.

New Accounting Pronouncements N

New Accounting Pronouncements New Accounting Pronouncements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Net Periodic Benefit Cost (Credit) Less Service Cost	$ 72
Capitalized Percentage Of Net Periodic Benefit Cost	41.00%

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	$ (156.3)	$ (127.1)	$ (103.1)
Change in Fair Value Recognized in AOCI	71.2	(28)	(20.7)
Commodity
Generation and Marketing Revenues	1,771.4	2,858.7	2,866.7
Purchased Electricity for Resale	2,965.3	2,821.4	2,760.1
Interest Rate
Interest Expense	895	877.2	873.9
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	26.4	(1.7)	(14.3)
Income Tax (Expense) Credit	(969.7)	73.7	(919.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	17.3	(1.2)	(9.3)
Net Current Period Other Comprehensive Income (Loss)	88.5	(29.2)	(30)
Pension and OPEB Adjustment Related to Mitchell Plant			6
Ending Balance in AOCI	(67.8)	(156.3)	(127.1)
Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	8.4	7.1	7.7
Change in Fair Value Recognized in AOCI	3.5	1.3	(0.6)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	3.5	1.3	(0.6)
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI	11.9	8.4	7.1
Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	140.5	139.9	138.7
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7	0.9	1.8
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.6	1.2
Net Current Period Other Comprehensive Income (Loss)	1.1	0.6	1.2
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI	141.6	140.5	139.9
Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(266.4)	(251.7)	(232)
Change in Fair Value Recognized in AOCI	86.5	(14.7)	(25.7)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	86.5	(14.7)	(25.7)
Pension and OPEB Adjustment Related to Mitchell Plant			6
Ending Balance in AOCI	(179.9)	(266.4)	(251.7)
Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(23.1)	(5.2)	1.6
Change in Fair Value Recognized in AOCI	(20.4)	(14.6)	5.6
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	23.2	(5)	(19)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	15.1	(3.3)	(12.4)
Net Current Period Other Comprehensive Income (Loss)	(5.3)	(17.9)	(6.8)
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI	(28.4)	(23.1)	(5.2)
Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(15.7)	(17.2)	(19.1)
Change in Fair Value Recognized in AOCI	1.6	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.5	2.4	2.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	1.5	1.9
Net Current Period Other Comprehensive Income (Loss)	2.7	1.5	1.9
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI	(13)	(15.7)	(17.2)
Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Generation and Marketing Revenues	(5.6)	(21.4)	(48.1)
Purchased Electricity for Resale	28.8	16.4	29.1
Interest Rate
Interest Expense	1.5	2.4	2.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(19.6)	(19.4)	(19.5)
Amortization of Actuarial (Gains)/Losses	21.3	20.3	21.3
Income Tax (Expense) Credit	9.1	(0.5)	(5)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Commodity
Generation and Marketing Revenues	0	0	0
Purchased Electricity for Resale	0	0	0
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Generation and Marketing Revenues	0	0	0
Purchased Electricity for Resale	0	0	0
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(19.6)	(19.4)	(19.5)
Amortization of Actuarial (Gains)/Losses	21.3	20.3	21.3
Income Tax (Expense) Credit	0.6	0.3	0.6
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Generation and Marketing Revenues	0	0	0
Purchased Electricity for Resale	0	0	0
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Generation and Marketing Revenues	(5.6)	(21.4)	(48.1)
Purchased Electricity for Resale	28.8	16.4	29.1
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	8.1	(1.7)	(6.6)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Generation and Marketing Revenues	0	0	0
Purchased Electricity for Resale	0	0	0
Interest Rate
Interest Expense	1.5	2.4	2.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0.4	0.9	1
AEP Texas Inc. [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(14.9)	(17.2)	(18.9)
Change in Fair Value Recognized in AOCI	1.1	0.8	0.1
Interest Rate
Interest Expense	142.3	144.4	148.4
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7	2.2	2.4
Income Tax (Expense) Credit	23.4	(59.9)	(58.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	1.5	1.6
Net Current Period Other Comprehensive Income (Loss)	2.3	2.3	1.7
Ending Balance in AOCI	(12.6)	(14.9)	(17.2)
AEP Texas Inc. [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	4.2	3.9	3.6
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.4	0.4	0.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.3	0.3
Net Current Period Other Comprehensive Income (Loss)	0.3	0.3	0.3
Ending Balance in AOCI	4.5	4.2	3.9
AEP Texas Inc. [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(13.7)	(14.6)	(14.8)
Change in Fair Value Recognized in AOCI	1.1	0.9	0.2
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	1.1	0.9	0.2
Ending Balance in AOCI	(12.6)	(13.7)	(14.6)
AEP Texas Inc. [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(5.4)	(6.5)	(7.7)
Change in Fair Value Recognized in AOCI	0	(0.1)	(0.1)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.3	1.8	1.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.9	1.2	1.3
Net Current Period Other Comprehensive Income (Loss)	0.9	1.1	1.2
Ending Balance in AOCI	(4.5)	(5.4)	(6.5)
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	1.3	1.8	1.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains)/Losses	0.5	0.5	0.6
Income Tax (Expense) Credit	0.5	0.7	0.8
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains)/Losses	0.5	0.5	0.6
Income Tax (Expense) Credit	0.1	0.1	0.2
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0	0	0
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	1.3	1.8	1.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0.4	0.6	0.6
AEP Transmission Co [Member]
Interest Rate
Interest Expense	68	46	34.6
Pension and OPEB
Income Tax (Expense) Credit	(147.2)	(94.1)	(60)
Appalachian Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(8.4)	(2.8)	5
Change in Fair Value Recognized in AOCI	11.6	(3.5)	(5.7)
Commodity
Purchased Electricity for Resale	357.6	329.3	395.2
Interest Rate
Interest Expense	190.9	188.5	192.3
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2.9)	(3.2)	(3.2)
Income Tax (Expense) Credit	(185.3)	(199.1)	(194.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.9)	(2.1)	(2.1)
Net Current Period Other Comprehensive Income (Loss)	9.7	(5.6)	(7.8)
Ending Balance in AOCI	1.3	(8.4)	(2.8)
Appalachian Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	16	17.4	19.2
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.8)	(2.1)	(2.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.2)	(1.4)	(1.8)
Net Current Period Other Comprehensive Income (Loss)	(1.2)	(1.4)	(1.8)
Ending Balance in AOCI	14.8	16	17.4
Appalachian Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(27.3)	(23.8)	(18.1)
Change in Fair Value Recognized in AOCI	11.6	(3.5)	(5.7)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	11.6	(3.5)	(5.7)
Ending Balance in AOCI	(15.7)	(27.3)	(23.8)
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	2.9	3.6	3.9
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.1)	(1.1)	(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.7)	(0.7)	(0.3)
Net Current Period Other Comprehensive Income (Loss)	(0.7)	(0.7)	(0.3)
Ending Balance in AOCI	2.2	2.9	3.6
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	(1.1)	(1.1)	(0.4)
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(5.2)	(5.1)	(5.1)
Amortization of Actuarial (Gains)/Losses	3.4	3	2.3
Income Tax (Expense) Credit	(1)	(1.1)	(1.1)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(5.2)	(5.1)	(5.1)
Amortization of Actuarial (Gains)/Losses	3.4	3	2.3
Income Tax (Expense) Credit	(0.6)	(0.7)	(1)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0	0	0
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	(1.1)	(1.1)	(0.4)
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	(0.4)	(0.4)	(0.1)
Indiana Michigan Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(16.2)	(16.7)	(14.3)
Change in Fair Value Recognized in AOCI	2.8	(0.8)	(3.5)
Commodity
Purchased Electricity for Resale	152.2	198.7	195.8
Interest Rate
Interest Expense	110.8	100.8	90.2
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	2	2	1.7
Income Tax (Expense) Credit	(81.4)	(67.5)	(96.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.3	1.3	1.1
Net Current Period Other Comprehensive Income (Loss)	4.1	0.5	(2.4)
Ending Balance in AOCI	(12.1)	(16.2)	(16.7)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5.1	5.1	5.1
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	0	0	0
Ending Balance in AOCI	5.1	5.1	5.1
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(9.3)	(8.5)	(5)
Change in Fair Value Recognized in AOCI	2.8	(0.8)	(3.5)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	2.8	(0.8)	(3.5)
Ending Balance in AOCI	(6.5)	(9.3)	(8.5)
Indiana Michigan Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(12)	(13.3)	(14.4)
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	2	2	1.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.3	1.3	1.1
Net Current Period Other Comprehensive Income (Loss)	1.3	1.3	1.1
Ending Balance in AOCI	(10.7)	(12)	(13.3)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	2	2	1.7
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(0.9)	(0.8)	(0.9)
Amortization of Actuarial (Gains)/Losses	0.9	0.8	0.9
Income Tax (Expense) Credit	0.7	0.7	0.6
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(0.9)	(0.8)	(0.9)
Amortization of Actuarial (Gains)/Losses	0.9	0.8	0.9
Income Tax (Expense) Credit	0	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	2	2	1.7
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0.7	0.7	0.6
Ohio Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	3
Commodity
Purchased Electricity for Resale	705.9	663.1	635
Interest Rate
Interest Expense	101.9	112.2	127.8
Pension and OPEB
Income Tax (Expense) Credit	(159.3)	(143.8)	(126.5)
Net Current Period Other Comprehensive Income (Loss)	(1.1)	(1.3)	(1.3)
Ending Balance in AOCI	1.9	3
Ohio Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	3	4.3	5.6
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.7)	(1.9)	(2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.1)	(1.3)	(1.3)
Net Current Period Other Comprehensive Income (Loss)	(1.1)	(1.3)	(1.3)
Ending Balance in AOCI	1.9	3	4.3
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	(1.7)	(1.9)	(2)
Pension and OPEB
Income Tax (Expense) Credit	(0.6)	(0.6)	(0.7)
Public Service Co Of Oklahoma [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	3.4
Commodity
Purchased Electricity for Resale	514.9	441.2	316.9
Interest Rate
Interest Expense	53.4	51.2	58.6
Pension and OPEB
Income Tax (Expense) Credit	(50.1)	(54.4)	(51.3)
Net Current Period Other Comprehensive Income (Loss)	(0.8)	(0.8)	(0.8)
Ending Balance in AOCI	2.6	3.4
Public Service Co Of Oklahoma [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	3.4	4.2	5
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.3)	(1.2)	(1.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.8)	(0.8)
Net Current Period Other Comprehensive Income (Loss)	(0.8)	(0.8)	(0.8)
Ending Balance in AOCI	2.6	3.4	4.2
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	(1.3)	(1.2)	(1.2)
Pension and OPEB
Income Tax (Expense) Credit	(0.5)	(0.4)	(0.4)
Southwestern Electric Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(9.4)	(9.4)	(7.5)
Change in Fair Value Recognized in AOCI	4.7	(1)	(2.9)
Commodity
Purchased Electricity for Resale	168.7	142.4	110.6
Interest Rate
Interest Expense	123.4	119.7	119.9
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.1	1.6	1.6
Income Tax (Expense) Credit	(48.1)	(52.1)	(84.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.7	1	1
Net Current Period Other Comprehensive Income (Loss)	5.4	0	(1.9)
Ending Balance in AOCI	(4)	(9.4)	(9.4)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	1.9	2.6	3.6
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.1)	(1.1)	(1.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.7)	(0.7)	(1)
Net Current Period Other Comprehensive Income (Loss)	(0.7)	(0.7)	(1)
Ending Balance in AOCI	1.2	1.9	2.6
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(3.9)	(2.9)	0
Change in Fair Value Recognized in AOCI	4.7	(1)	(2.9)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Net Current Period Other Comprehensive Income (Loss)	4.7	(1)	(2.9)
Ending Balance in AOCI	0.8	(3.9)	(2.9)
Southwestern Electric Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(7.4)	(9.1)	(11.1)
Change in Fair Value Recognized in AOCI	0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	2.2	2.7	3.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.4	1.7	2
Net Current Period Other Comprehensive Income (Loss)	1.4	1.7	2
Ending Balance in AOCI	(6)	(7.4)	(9.1)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	2.2	2.7	3.1
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(2)	(1.8)	(1.9)
Amortization of Actuarial (Gains)/Losses	0.9	0.7	0.4
Income Tax (Expense) Credit	0.4	0.6	0.6
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(2)	(1.8)	(1.9)
Amortization of Actuarial (Gains)/Losses	0.9	0.7	0.4
Income Tax (Expense) Credit	(0.4)	(0.4)	(0.5)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	0	0	0
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	2.2	2.7	3.1
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Actuarial (Gains)/Losses	0	0	0
Income Tax (Expense) Credit	$ 0.8	$ 1	$ 1.1

Rate Matters - East Companies

Rate Matters - East Companies (Details) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 22, 2018USD ($)	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			$ 4,120.7	$ 3,183.9
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			483	390.3
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			460.2	654.2
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			410.1	$ 221.5
2017 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 263
Requested Return on Equity			10.60%
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider			$ 23
Amount Of Increased Depreciation Expense Requested			78
Amount of Increase Related to Amortization of Regulatory Assets			11
2017 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 263
Requested Return on Equity			10.60%
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider			$ 23
Amount Of Increased Depreciation Expense Requested			78
Amount of Increase Related to Amortization of Regulatory Assets			11
2017 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 52
Requested Return on Equity			10.60%
Amount Of Increased Depreciation Expense Requested			$ 23
Amount of Increase Related to Amortization of Regulatory Assets			4
MPSC Recommended Annual Net Revenue Increase			$ 49
MPSC Recommended Return on Common Equity			9.80%
Percent of I&M Customers Receiving Market Based Capacity Charge			10.00%
2017 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 52
Requested Return on Equity			10.60%
Amount Of Increased Depreciation Expense Requested			$ 23
Amount of Increase Related to Amortization of Regulatory Assets			4
MPSC Recommended Annual Net Revenue Increase			$ 49
MPSC Recommended Return on Common Equity			9.80%
Percent of I&M Customers Receiving Market Based Capacity Charge			10.00%
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs			$ 274
Construction Work in Progress			23
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			23
2017 Kentucky Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 66
Requested Return on Equity			10.31%
Requested Annual Increase in Environmental Surcharge			$ 4
Adjusted Requested Annual Increase			60
Non-Unanimous Settlement Agreement Proposed Annual Base Rate Increase			$ 32
Non-Unanimous Settlement Agreement Proposed Return on Common Equity			9.75%
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Solar Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW			400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | 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%
PUCO Approved Reduced Customer Credits			$ 15
Return on Common Equity Proposed in the Amended ESP Filing			10.41%
Intervenor Recommended Return on Common Equity			9.30%
Return on Common Equity Filed in the Pending Stipulation Agreement			10.00%
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Solar Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW			400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | 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%
PUCO Approved Reduced Customer Credits			$ 15
Return on Common Equity Proposed in the Amended ESP Filing			10.41%
Intervenor Recommended Return on Common Equity			9.30%
Return on Common Equity Filed in the Pending Stipulation Agreement			10.00%
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
FERC Transmission Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity			10.99%
Intervenor Recommended Return on Common Equity			8.32%
Subsequent Event [Member] | Virginia Legislation Affecting Biennial Reviews [Member]
Public Utilities, General Disclosures [Line Items]
Fuel Expenses Not to be Recovered	$ 10
Reduction in Annual Base Rates	50
Subsequent Event [Member] | Virginia Legislation Affecting Biennial Reviews [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Fuel Expenses Not to be Recovered	10
Reduction in Annual Base Rates	50
Subsequent Event [Member] | 2017 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted Annual Increase Request due to Tax Reform		$ 191
Setlled Annual Increase	$ 97
Settled Return on Common Equity	9.95%
Original Sharing of Off-System Sales Margins	50.00%
Settled Sharing of Off-System Sales Margins	95.00%
Refund for Impact of Tax Reform	$ 4
Subsequent Event [Member] | 2017 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted Annual Increase Request due to Tax Reform		191
Setlled Annual Increase	$ 97
Settled Return on Common Equity	9.95%
Original Sharing of Off-System Sales Margins	50.00%
Settled Sharing of Off-System Sales Margins	95.00%
Refund for Impact of Tax Reform	$ 4
Subsequent Event [Member] | 2017 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
ALJ Recommended Annual Increase	$ 49
ALJ Recommended Return on Common Equity	9.80%
Reduced Capacity Charge Pretax Loss	$ 9
Alternate Supplier Cap	10.00%
Subsequent Event [Member] | 2017 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
ALJ Recommended Annual Increase	$ 49
ALJ Recommended Return on Common Equity	9.80%
Reduced Capacity Charge Pretax Loss	$ 9
Alternate Supplier Cap	10.00%
Subsequent Event [Member] | 2017 Kentucky Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
KPSC Order Annual Revenue Increase		$ 12
KPSC Order Return on Common Equity		9.70%
KPSC Order Annual Revenue Reduction due to Tax Reform		$ 14
KPSC Order Deferral of Rockport Plant Unit Power Agreement Expenses		$ 50
Recovery/Return of certain PJM OATT Expenses Above/Below Corresponding Level Recovered in Rates		80.00%
KPCo Request for Additional Revenue Increase	$ 2.3
Subsequent Event [Member] | 2016 SEET Filing [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Refund to Customers		$ 53
Subsequent Event [Member] | 2016 SEET Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Refund to Customers		$ 53
Minimum [Member] | 2017 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase			$ 125
Intervenor Recommended Return on Common Equity			8.65%
Minimum [Member] | 2017 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase			$ 125
Intervenor Recommended Return on Common Equity			8.65%
Minimum [Member] | 2017 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity			9.30%
Minimum [Member] | 2017 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity			9.30%
Minimum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range			$ 215
Minimum [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range			215
Maximum [Member] | 2017 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase			$ 152
Intervenor Recommended Return on Common Equity			9.10%
Maximum [Member] | 2017 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase			$ 152
Intervenor Recommended Return on Common Equity			9.10%
Maximum [Member] | 2017 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity			9.50%
Maximum [Member] | 2017 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity			9.50%
Maximum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range			$ 290
Maximum [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range			$ 290

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 4,120.7	$ 3,183.9
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		835.7	385.9
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		111.3	148.2
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		233.2	$ 113.8
AEP Texas Interim Transmission and Distribution Rates [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		763
AEP Texas Interim Transmission and Distribution Rates [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		763
Hurricane Harvey Storm [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates		1
AEP Texas Total Storm-Related Costs		123
AEP Texas Hurricane Harvey Storm-Related Costs		100
AEP Texas Hurricane Harvey Storm-Capital Expenditures		133
AEP Texas Hurricane Harvey Storm Insurance Proceeds Received		10
Hurricane Harvey Storm [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates		1
AEP Texas Total Storm-Related Costs		123
AEP Texas Hurricane Harvey Storm-Related Costs		100
AEP Texas Hurricane Harvey Storm-Capital Expenditures		133
AEP Texas Hurricane Harvey Storm Insurance Proceeds Received		$ 10
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Equity Ownership Interest in ETT		50.00%
AEP Share of ETT Cumulative Revenues Subject to Review		$ 746
2017 Oklahoma Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		156
Refund Obligation		11
Requested Annual Net Increase		$ 145
Requested Return on Equity		10.00%
Amount Of Increased Depreciation Expense Requested		$ 42
Property, Plant and Equipment, Net		81
2017 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		156
Refund Obligation		11
Requested Annual Net Increase		$ 145
Requested Return on Equity		10.00%
Amount Of Increased Depreciation Expense Requested		$ 42
Property, Plant and Equipment, Net		81
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
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
Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		33.00%
Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		33.00%
2015 Louisiana Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 14
2015 Louisiana Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14
2017 Louisiana Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		31
2017 Louisiana Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		31
Welsh Plant - Environmental Impact [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		850
Construction Work in Progress		398
Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		131
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
Welsh Plant - Environmental Impact [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 Louisiana Retail Jurisdictional Share Of Environmental Costs		131
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
Welsh Plant - Environmental Impact [Member] | Welsh Plant, Units 1 and 3 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		627
Welsh Plant - Environmental Impact [Member] | Welsh Plant, Units 1 and 3 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		$ 627
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%
FERC SWEPCo Power Supply Agreements Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		11.10%
Intervenor Recommended Return on Common Equity		8.41%
Subsequent Event [Member] | 2017 Oklahoma Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Approved Increase in Oklahoma Annual Gross Revenues	$ 84
Approved Reduction in Oklahoma Annual Revenues Due to Tax Reform	32
Approved Increase in Oklahoma Annual Net Revenues	$ 52
Approved Return on Common Equity	9.30%
Amount of Increased Depreciation Expenses Approved	$ 19
Subsequent Event [Member] | 2017 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Approved Increase in Oklahoma Annual Gross Revenues	84
Approved Reduction in Oklahoma Annual Revenues Due to Tax Reform	32
Approved Increase in Oklahoma Annual Net Revenues	$ 52
Approved Return on Common Equity	9.30%
Amount of Increased Depreciation Expenses Approved	$ 19
Subsequent Event [Member] | 2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	9.60%
Approved Net Increase in Texas Annual Revenues	$ 50
Approved Additional Vegetation Management Expenses	2
Impairment Charge Total	19
Impairment Charge Welsh Plant, Unit 2	7
Impairment Charge Disallowed Plant Investments	12
Additional Revenues Recognized to be Surcharged to Customers	32
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management	$ 7
Subsequent Event [Member] | 2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	9.60%
Approved Net Increase in Texas Annual Revenues	$ 50
Approved Additional Vegetation Management Expenses	2
Impairment Charge Total	19
Impairment Charge Welsh Plant, Unit 2	7
Impairment Charge Disallowed Plant Investments	12
Additional Revenues Recognized to be Surcharged to Customers	32
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management	7
Subsequent Event [Member] | Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
Impairment Charge Total	15
Pretax Write-Off of the LA Share of Previously Capitalized Turk Plant Costs	19
Rate Refund Provision for Previously Collected Revenues on Disallowed Portion of Turk Plant	10
Pretax Write-Off as a Result of Agreement	23
Pretax Provision for Revenue Refund	8
Amount to be Refunded to Customers in First Billing Cycle Following Commission Approval	2
Amount to be Amortized as a Cost of Service Reduction Over 5 Years effective Aug 1, 2018	8
Subsequent Event [Member] | Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Impairment Charge Total	15
Pretax Write-Off of the LA Share of Previously Capitalized Turk Plant Costs	19
Rate Refund Provision for Previously Collected Revenues on Disallowed Portion of Turk Plant	10
Pretax Write-Off as a Result of Agreement	23
Pretax Provision for Revenue Refund	8
Amount to be Refunded to Customers in First Billing Cycle Following Commission Approval	2
Amount to be Amortized as a Cost of Service Reduction Over 5 Years effective Aug 1, 2018	$ 8

Effects of Regulation (Details)

Effects of Regulation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2017
Regulatory Assets
Current Regulatory Assets		$ 292.5	$ 156.6
Noncurrent Regulatory Assets		3,587.6	5,625.5
Regulatory Liabilities
Current Regulatory Liabilities		11.9	8
Noncurrent Regulatory Liabilities		8,422.3	3,751.3
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 17,167	$ 16,397.3
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 378.7	$ 347.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,320.5	660.8
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 1,594.5	$ 1,542
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.7	$ 112.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		493.7	44
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 170.4	$ 99.6
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 88.8	$ 68.4
Noncurrent Regulatory Assets		573.9	1,121.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,454.9	627.8
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 3,896.4	$ 3,636.8
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 15	$ 26.1
Noncurrent Regulatory Assets		579.4	916.6
Regulatory Liabilities
Current Regulatory Liabilities		2.7	0
Noncurrent Regulatory Liabilities		1,708.7	1,065.5
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 3,024.2	$ 3,005.1
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
Ohio Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 115.9	$ 0
Noncurrent Regulatory Assets		652.8	1,107.5
Regulatory Liabilities
Current Regulatory Liabilities		0	4.2
Noncurrent Regulatory Liabilities		1,100.2	506.2
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 2,184.8	$ 2,116
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
Public Service Co Of Oklahoma [Member]
Regulatory Assets
Current Regulatory Assets		$ 36.7	$ 33.8
Noncurrent Regulatory Assets		368.1	340.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		853.5	339.7
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 1,393.6	$ 1,272.7
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 14.1	$ 8.4
Noncurrent Regulatory Assets		220.6	551.2
Regulatory Liabilities
Current Regulatory Liabilities		8.7	3.8
Noncurrent Regulatory Liabilities		896.4	438.9
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 2,685.8	$ 2,567.1
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Future		21.00%
Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 4,009.3	$ 3,750.5
Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		677.6	660.8
Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		66.7	44
Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		634.6	627.8
Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,236	1,065.5
Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		495.8	506
Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		321.8	339.7
Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		440.5	438.9
Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		4,413	0.8
Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		642.9	0
Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		427	0
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		820.3	0
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		472.7	0
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		604.4	0.2
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		531.7	0
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		455.9	0
Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[1]	322	450.1
Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		123.4	25.2
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[2]	49.4	39.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		79.3	64.7
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	100.8
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3.3	118.1
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		64.9	95.9
Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3,265.6	5,175.4
Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		255.3	322
Regulatory Assets Approved for Recovery [Member] | AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		11.7	112.3
Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		524.5	1,081.8
Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		500.1	851.9
Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		652.8	1,006.7
Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		364.8	222.1
Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		155.7	455.3
Advanced Metering Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0.6	11.5
Remaining Refund Period		1 year
Advanced Metering Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.5	20.9
Regulatory Asset, Amortization Period		3 years
Advanced Metering Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.5	21.3
Regulatory Asset, Amortization Period		3 years
Advanced Metering Infrastructure Surcharge [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 12.7	17
Remaining Refund Period		3 years
Advanced Metering Infrastructure Surcharge [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 12.7	17
Remaining Refund Period		3 years
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3],[4]	$ 2,637.1	2,627.5
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	599.2	581.7
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	66.7	44
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	615.8	616.9
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8],[9]	202.2	236.5
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	428.8	432.4
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[11]	268.8	279.3
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[12]	424.5	409.7
Asset Removal Costs - Tanners Creek Plant Retirement [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		43
Asset Removal Costs - Tanners Creek Plant Retirement [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		43
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]
Regulatory Assets
Noncurrent Regulatory Assets		4	2.7
Basic Transmission Cost Rider [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 90.8	19.9
Regulatory Asset, Amortization Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 90.8	19.9
Regulatory Asset, Amortization Period		2 years
Consumer Rate Relief - West Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 6.5	5.1
Remaining Refund Period		1 year
Cook Plant Nuclear Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 66.7	75.2
Regulatory Asset, Amortization Period		2 years
Cook Plant Nuclear Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 66.7	75.2
Regulatory Asset, Amortization Period		2 years
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.9	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]
Regulatory Assets
Noncurrent Regulatory Assets		15.9	12.8
Cook Plant, Unit 2 Baffle Bolts - Indiana [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6	6.3
Regulatory Asset, Amortization Period		21 years
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 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]
Regulatory Assets
Noncurrent Regulatory Assets		36.3	36.3
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 3.2	4.2
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 2.7	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 0	4.2
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 8.7	3.8
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 8.7	3.8
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 203.1	61.4
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 21.4	6.2
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 15	13
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Ohio Power Co [Member]
Regulatory Assets
Current Regulatory Assets	[13]	$ 115.9	0
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Current Regulatory Assets		$ 36.7	33.8
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 14.1	8.4
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	218.9
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	218.9
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 89.4	95.2
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 67.4	62.2
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 0	13.1
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 191.2	132.9
Remaining Refund Period		45 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 12.3	13.9
Remaining Refund Period		45 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 34.1	38.8
Remaining Refund Period		20 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 50.7	48
Remaining Refund Period		41 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 5.9	7.3
Remaining Refund Period		14 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 10.6	12.6
Remaining Refund Period		41 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0.9	0.9
Remaining Refund Period		41 years
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]
Regulatory Assets
Noncurrent Regulatory Assets		$ 14.7	8.1
Defrred PJM Fees [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 48	0
Regulatory Asset, Amortization Period		2 years
Defrred PJM Fees [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 48	0
Regulatory Asset, Amortization Period		2 years
Deferred System Reliability Rider Expenses [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	12.5
Enhanced Service Reliability Plan [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 30.6	21.7
Remaining Refund Period		2 years
Enhanced Service Reliability Plan [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 30.6	21.7
Remaining Refund Period		2 years
Environmental Controls Projects [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 28.1	0
Regulatory Asset, Amortization Period		23 years
Environmental Controls Projects [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 28.1	0
Regulatory Asset, Amortization Period		23 years
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	24.1
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	13.1
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	11
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.3	0
Regulatory Asset, Amortization Period		15 years
Excess Asset Retirement Obligations For Nuclear Decommissioning Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[14]	$ 945	731.2
Excess Asset Retirement Obligations For Nuclear Decommissioning Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[15]	945	731.2
Excess Earnings [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 9.4	10
Remaining Refund Period		36 years
Excess Earnings - Texas [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 6.8	7.3
Remaining Refund Period		14 years
Generation Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.3	6.5
Regulatory Asset, Amortization Period		2 years
gridSMART Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.4	11.9
Remaining Refund Period		1 year
gridSMART Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	4.1
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[16]	4,412.8	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[17]	642.9	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[18]	427	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[19]	820.3	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[20]	472.7	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[21]	604.2	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[22]	531.7	0
Income Taxes, Net [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[23]	455.9	0
Income Taxes, Net [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	106.1
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	1,575
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	40.3
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	463.5
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	302.6
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	126.4
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	9.3
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	314.2
Louisiana Refundable Construction Financing Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	16.2
Louisiana Refundable Construction Financing Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	16.2
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		9.1	9.1
Mitchell Plant Transfer [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 17.8	18.5
Regulatory Asset, Amortization Period		23 years
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9	24.3
Regulatory Asset, Amortization Period		2 years
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9	24.3
Regulatory Asset, Amortization Period		2 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	96.7
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[24]	0	96.7
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 172.6	201.9
Regulatory Asset, Amortization Period		2 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 172.6	201.9
Regulatory Asset, Amortization Period		2 years
Ohio Distribution Decoupling [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 61.7	41.8
Regulatory Asset, Amortization Period		2 years
Ohio Distribution Decoupling [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 61.7	41.8
Regulatory Asset, Amortization Period		2 years
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 41	55.4
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3.9	6.8
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1	2.5
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.7	4.2
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.5	0
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		7.2	1.3
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		122.9	100.7
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		8.5	9.8
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		22	28.4
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		20	16
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		15.8	18.6
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		4.1	5.4
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		6.2	10.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		9.6	10.4
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]
Regulatory Assets
Noncurrent Regulatory Assets		0	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]
Regulatory Assets
Noncurrent Regulatory Assets		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]
Regulatory Assets
Noncurrent Regulatory Assets		42.2	29.3
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]
Regulatory Assets
Noncurrent Regulatory Assets		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]
Regulatory Assets
Noncurrent Regulatory Assets		2	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]
Regulatory Assets
Noncurrent Regulatory Assets		0.1	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]
Regulatory Assets
Noncurrent Regulatory Assets		2.5	1.9
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		56.6	61.1
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.6	0.4
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.9	3.6
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		11.5	14.8
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		10	10.7
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.7	0.9
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		7.5	1.8
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.3	1.6
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.4	0.3
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		2.6	3.9
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.8
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.2
OVEC Purchased Power [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	22.1
OVEC Purchased Power [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	22.1
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 25.6	34
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 23.6	29
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 40.1	49.9
Regulatory Asset, Amortization Period		3 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 13	10.3
Regulatory Asset, Amortization Period		2 years
Peak Demand Reduction/Energy Efficiency - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.1	19.2
Regulatory Asset, Amortization Period		3 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 34.3	18.3
Regulatory Asset, Amortization Period		23 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 39.7	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]
Regulatory Assets
Noncurrent Regulatory Assets		39.7	29.6
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 37.2	48.9
Regulatory Asset, Amortization Period		23 years
Plant Retirement Costs - Northeastern Plant, Unit 3 [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 57			$ 41
Plant Retirement Costs - Northeastern Plant, Unit 3 [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		57			$ 41
Plant Retirement Costs - Unrecovered Plant [Member]
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Appalachian Power Co [Member]
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		50.3	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]
Regulatory Assets
Noncurrent Regulatory Assets		0	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]
Regulatory Assets
Noncurrent Regulatory Assets		50.3	75.4
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[25]	$ 682.6	550.6
Regulatory Asset, Amortization Period		27 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 86.3	85.4
Regulatory Asset, Amortization Period		26 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 245.3	252.8
Regulatory Asset, Amortization Period		27 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[26]	$ 138.5	0
Regulatory Asset, Amortization Period		23 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 17.6	0
Regulatory Asset, Amortization Period		24 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 39.1	39.1
Regulatory Asset, Amortization Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.8	17.4
Regulatory Asset, Amortization Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.7	11.4
Regulatory Asset, Amortization Period		5 years
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.1	0.1
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		4.3	1
Red Rock Generating Facility [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.8	9.1
Regulatory Asset, Amortization Period		39 years
Rockport Plant 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]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.4	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]
Regulatory Assets
Noncurrent Regulatory Assets		3.3	3.1
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[14]	43.2	44.2
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[15]	43.2	44.2
Storm Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	25.1
Storm Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	25.1
Storm Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 39.3	15.3
Regulatory Asset, Amortization Period		4 years
Storm Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 39	10.8
Regulatory Asset, Amortization Period		4 years
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[27]	$ 128	25.9
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[28]	123.3	0
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3.2	20
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 44.2	58.7
Regulatory Asset, Amortization Period		6 years
Storm Related Costs - Hurricane Harvey [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 100
Storm Related Costs - Hurricane Harvey [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		100
Storm Related Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 32.2	47.8
Regulatory Asset, Amortization Period		3 years
SPP Base Plan Fees [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 16.3	10.7
Regulatory Asset, Amortization Period		2 years
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 83.7	99.9
Regulatory Asset, Amortization Period		10 years
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 44.9	49.8
Regulatory Asset, Amortization Period		10 years
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 38.8	50.1
Regulatory Asset, Amortization Period		7 years
Transition Charges [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 46	40.5
Remaining Refund Period		10 years
Transition Charges [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 46	40.5
Remaining Refund Period		10 years
Transmission Cost Recovery Factor [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.5	5.3
Regulatory Asset, Amortization Period		1 year
Transmission Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 32.6	38.7
Regulatory Asset, Amortization Period		2 years
Transmission Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 32.6	38.7
Regulatory Asset, Amortization Period		2 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 129.9	137.8
Regulatory Asset, Amortization Period		28 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.7	7.3
Regulatory Asset, Amortization Period		20 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 93.2	97.2
Regulatory Asset, Amortization Period		28 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.5	10.7
Regulatory Asset, Amortization Period		15 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.8	9.1
Regulatory Asset, Amortization Period		21 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5	5.8
Regulatory Asset, Amortization Period		15 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.7	5.4
Regulatory Asset, Amortization Period		26 years
Under-Recovered OATT Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.7	4.6
Regulatory Asset, Amortization Period		1 year
Under-Recovered SPP Revenues [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	1.6
United Mine Workers of America Pension Withdrawal [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.5	20.2
Regulatory Asset, Amortization Period		5 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 9.5	1.3
Remaining Refund Period		7 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 139.3	119.1
Regulatory Asset, Amortization Period		15 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 131.8	118.6
Regulatory Asset, Amortization Period		15 years
Vegetation Management [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.5	31.4
Regulatory Asset, Amortization Period		7 years
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.5	31.4
Regulatory Asset, Amortization Period		7 years
West Virginia Delayed Customer Billing [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.4	19.5
Regulatory Asset, Amortization Period		1 year
West Virginia Delayed Customer Billing [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.8	18.1
Regulatory Asset, Amortization Period		1 year
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 32.5	37.2
Regulatory Asset, Amortization Period		7 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.1	8.2
Regulatory Asset, Amortization Period		7 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.7	4.3
Regulatory Asset, Amortization Period		7 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1,196.3	1,516.2
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 151.2	188.2
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 168.8	221.4
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 77.8	141.9
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 170.6	225.2
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 72.7	98.1
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 101	$ 119.8
Regulatory Asset, Amortization Period		12 years
[1]	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. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.
[2]	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. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.
[3]	As of December 31, 2017, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases.
[4]	Relieved as removal costs are incurred.
[5]	Relieved as removal costs are incurred.
[6]	Relieved as removal costs are incurred.
[7]	Relieved as removal costs are incurred.
[8]	As of December 31, 2017, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases.
[9]	Relieved as removal costs are incurred.
[10]	Relieved as removal costs are incurred.
[11]	Relieved as removal costs are incurred.
[12]	Relieved as removal costs are incurred.
[13]	December 31, 2017 balance includes Phase-In Recovery Rider.
[14]	Relieved when plant is decommissioned.
[15]	Relieved when plant is decommissioned.
[16]	This balance primarily represents regulatory liabilities for excess accumulated deferred income taxes (Excess ADIT) as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[17]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[18]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[19]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[20]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[21]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[22]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[23]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. The mechanism and refund period to provide the Excess ADIT to customers will be based on future orders from the respective commission in each jurisdiction. See “Federal Tax Reform” section of Note 12 for additional information.
[24]	Capacity Deferral related to 2016 Global Settlement was approved for recovery effective March 2017.
[25]	In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of December 31, 2017 the unrecovered plant balance related to Northeastern Plant, Unit 3 was $57 million.
[26]	In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of December 31, 2017 the unrecovered plant balance related to Northeastern Plant, Unit 3 was $57 million.
[27]	As of December 31, 2017, AEP Texas has deferred $100 million related to Hurricane Harvey and is currently exploring recovery options.
[28]	As of December 31, 2017, AEP Texas has deferred $100 million related to Hurricane Harvey and is currently exploring recovery options.

Commitments, Guarantees and C62

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Contractual Commitments
Less than 1 year		$ 1,297,700
For 2-3 years		1,475,600
For 4-5 years		922,900
After 5 years		1,688,900
Total Contractual Commitments		5,385,100
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		3,000,000
Disposal, Assessed Fees and Related Interest	[1]	268,600	$ 266,300
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		103,500
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported		45,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Letters of Credit Limit		1,200,000
Uncommitted Facility		345,000
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		115,000
Estimated Final Cost Mine Reclamation		76,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		72,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		76,000
Amount Collected, Rider Mine Close Other Assets Noncurrent		4,000
Equity Method Investee [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Amount of Future Payments Associated with Guarantee		75,000
Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	1,067,600
For 2-3 years	[2]	1,019,500
For 4-5 years	[2]	544,900
After 5 years	[2]	221,600
Total Contractual Commitments	[2]	2,853,600
Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		230,100
For 2-3 years		456,100
For 4-5 years		378,000
After 5 years		1,467,300
Total Contractual Commitments		2,531,500
AEP Texas Inc. [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		2,800
Appalachian Power Co [Member]
Contractual Commitments
Less than 1 year		405,100
For 2-3 years		436,700
For 4-5 years		238,100
After 5 years		355,800
Total Contractual Commitments		1,435,700
Appalachian Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	369,100
For 2-3 years	[2]	364,400
For 4-5 years	[2]	165,200
After 5 years	[2]	900
Total Contractual Commitments	[2]	899,600
Appalachian Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		36,000
For 2-3 years		72,300
For 4-5 years		72,900
After 5 years		354,900
Total Contractual Commitments		536,100
Indiana Michigan Power Co [Member]
Contractual Commitments
Less than 1 year		362,300
For 2-3 years		525,300
For 4-5 years		464,500
After 5 years		519,000
Total Contractual Commitments		1,871,100
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Disposal, Assessed Fees and Related Interest	[1]	268,600	266,300
Indiana Michigan Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	236,900
For 2-3 years	[2]	269,400
For 4-5 years	[2]	204,600
After 5 years	[2]	166,600
Total Contractual Commitments	[2]	877,500
Indiana Michigan Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		125,400
For 2-3 years		255,900
For 4-5 years		259,900
After 5 years		352,400
Total Contractual Commitments		993,600
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		600
Ohio Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		29,900
For 2-3 years		59,300
For 4-5 years		58,400
After 5 years		363,700
Total Contractual Commitments		511,300
Public Service Co Of Oklahoma [Member]
Contractual Commitments
Less than 1 year		137,400
For 2-3 years		253,200
For 4-5 years		158,300
After 5 years		236,800
Total Contractual Commitments		785,700
Public Service Co Of Oklahoma [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	45,900
For 2-3 years	[2]	71,700
For 4-5 years	[2]	30,500
After 5 years	[2]	0
Total Contractual Commitments	[2]	148,100
Public Service Co Of Oklahoma [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		91,500
For 2-3 years		181,500
For 4-5 years		127,800
After 5 years		236,800
Total Contractual Commitments		637,600
Southwestern Electric Power Co [Member]
Contractual Commitments
Less than 1 year		144,700
For 2-3 years		153,100
For 4-5 years		108,800
After 5 years		151,000
Total Contractual Commitments		557,600
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		115,000
Estimated Final Cost Mine Reclamation		76,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		72,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		76,000
Amount Collected, Rider Mine Close Other Assets Noncurrent		4,000
Southwestern Electric Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	111,700
For 2-3 years	[2]	85,800
For 4-5 years	[2]	55,400
After 5 years	[2]	0
Total Contractual Commitments	[2]	252,900
Southwestern Electric Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		33,000
For 2-3 years		67,300
For 4-5 years		53,400
After 5 years		151,000
Total Contractual Commitments		304,700
Comprehensive Environmental Response Compensation and Liabilities Act and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		100
Comprehensive Environmental Response Compensation and Liabilities Act and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		100
Decommissioning and Low Level Waste Accumulation Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Cost of Decommissioning and Disposal of Radioactive Waste		1,600,000
Additional Ongoing Costs for Post Decommissioning Storage of SNF		5,000
Subsequent Decommissioning of the Spent Fuel Storage Facility		57,000
Amount Recovered in Rates for Decommissioning Costs		9,000	9,000	$ 9,000
Decommissioning Fund Investments, Fair Value		2,200,000	1,900,000
Decommissioning and Low Level Waste Accumulation Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Cost of Decommissioning and Disposal of Radioactive Waste		1,600,000
Additional Ongoing Costs for Post Decommissioning Storage of SNF		5,000
Subsequent Decommissioning of the Spent Fuel Storage Facility		57,000
Amount Recovered in Rates for Decommissioning Costs		9,000	9,000	9,000
Decommissioning Fund Investments, Fair Value		2,200,000	1,900,000
Nuclear Incident Liability [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Insurance Coverage for Property Damage, Decommissioning and Decontamination		3,000,000
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,500,000
Contingent Financial Obligation for Mutual Insurance		51,000
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,400,000
Commercially Available Insurance		450,000
Remainder of the Liability Provided by a Deferred Premium Assessment		127,000
Deferred Premium Assessment Annual Payment		19,000
Assessed Amount per Nuclear Incident		255,000
Annual Installments		38,000
Commercially Available Insurance for Catastrophic Nature		450,000
Liability Coverage Under the Price-Anderson Act		13,000,000
Nuclear Incident Liability [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Insurance Coverage for Property Damage, Decommissioning and Decontamination		3,000,000
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,500,000
Contingent Financial Obligation for Mutual Insurance		51,000
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,400,000
Commercially Available Insurance		450,000
Remainder of the Liability Provided by a Deferred Premium Assessment		127,000
Deferred Premium Assessment Annual Payment		19,000
Assessed Amount per Nuclear Incident		255,000
Annual Installments		38,000
Commercially Available Insurance for Catastrophic Nature		450,000
Liability Coverage Under the Price-Anderson Act		13,000,000
Spent Nuclear Fuel Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Disposal, Assessed Fees and Related Interest		269,000	266,000
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		312,000	311,000
Recovery of Spent Nuclear Fuel Storage Costs		22,000	6,000	13,000
Current Amount Recoverable from the Federal Government		11,000
Noncurrent Amount Recoverable from the Federal Government		5,000
Spent Nuclear Fuel Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Disposal, Assessed Fees and Related Interest		269,000	266,000
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		312,000	311,000
Recovery of Spent Nuclear Fuel Storage Costs		22,000	$ 6,000	$ 13,000
Current Amount Recoverable from the Federal Government		11,000
Noncurrent Amount Recoverable from the Federal Government		5,000
July 2019 [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Bilateral Letters of Credit		46,000
June 2021 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		3,000,000
October 2017 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Uncommitted Facility		$ 100,000
[1]	Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).
[2]	Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

Dispositions, Assets and Liab63

Dispositions, Assets and Liabilities Held for Sale and Impairments (Details) - USD ($) $ in Millions		3 Months Ended									9 Months Ended	12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Make Whole Premium on Extinguishment of Long-term Debt												$ 46.1	$ 0	$ 92.7
Disposal Group, Balance Sheet Disclosure [Abstract]
Total Assets from Discontinued Operations on the Balance Sheet			$ 1,951.2										1,951.2
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		$ 0		$ (2.5)	[1]	$ 0			0	(2.5)	283.7
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges												87.1	2,267.8	0
Corporate and Other [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue														447.1
Other Operation Expense														321.3
Maintenance Expense														21.5
Depreciation and Amortization Expense														26.9
Taxes Other Than Income Taxes														10.6
Total Expenses														380.3
Other Income (Expense)														(16.9)
Pretax Income of Discontinued Operations														49.9
Income Tax Expense														19.4
Equity Earnings of Unconsolidated Subsidiaries														(0.1)
Income from Discontinued Operations of AEPRO														30.4
Gain on Sale of Discontinued Operations														240.1
Income Tax Expense (Benefit)														(13.2)
Gain on Sale of Discontinued Operations, Net of Tax														253.3
Total Income on Discontinued Operations as Presented on the Statements of Income														283.7
Vertically Integrated Utilities [Member]
Disposal Group, Balance Sheet Disclosure [Abstract]
Total Assets from Discontinued Operations on the Balance Sheet			0										0
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income												0	0	0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges												33.6	10.5
Vertically Integrated Utilities [Member] | Tanners Creek Plant Units 1 Through 4 [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Payment On Sale Of Property Plant And Equipment													92
Vertically Integrated Utilities [Member] | Welsh Plant Unit 2 [Member]
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges		$ 19
Vertically Integrated Utilities [Member] | Turk Generating Plant [Member]
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges		15
Generation and Marketing [Member]
Income (Loss) from Individually Significant Component Disposed of or Held-for-sale, Excluding Discontinued Operations, before Income Tax													375	451
Disposal Group, Balance Sheet Disclosure [Abstract]
Fuel			145.5										145.5
Materials and Supplies			49.4										49.4
Property, Plant and Equipment - Net			1,756.2										1,756.2
Other Classes of Assets That Are Not Major			0.1										0.1
Total Assets from Discontinued Operations on the Balance Sheet			1,951.2										1,951.2
Long-term Debt			134.8										134.8
Waterford Plant Upgrade Liability			52.2										52.2
Asset Retirement Obligations			36.7										36.7
Other Classes of Liabilities That Are Not Major			12.2										12.2
Total Liabilities from Discontinued Operations on the Balance Sheet			235.9										235.9
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income												0	0	0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges												53.5	2,257.3
Generation and Marketing [Member] | Gavin, Waterford, Darby and Lawrenceburg Plants [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal												226
Proceeds from Sales of Assets, Investing Activities												2,200
Cash Proceeds from Disposition of Business, Net												1,200
Generation and Marketing [Member] | Muskingum River Plant [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Payment On Sale Of Property Plant And Equipment														48
Gain (Loss) on Disposition of Assets														32
AEP Texas Inc. [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue													18.2	22.4
Other Operation Expense													6.5	6.5
Maintenance Expense													3.4	4.9
Depreciation and Amortization Expense													9.8	11.5
Taxes Other Than Income Taxes													1.3	1.3
Total Expenses													93.7	24.2
Other Income (Expense)													(0.8)	(1.3)
Pretax Income of Discontinued Operations													(76.3)	(3.1)
Income Tax Expense													(27.5)	(1.7)
Total Income on Discontinued Operations as Presented on the Statements of Income			0.6	[2]	(47.4)	[2]	(0.7)	[2]	(1.3)	[2]		0	(48.8)	(1.4)
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges													72.7	0
Disposal Group, Including Discontinued Operation, Operating Income (Loss)													(48.8)	(1.4)
AEP Transmission Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		0		0		0
Appalachian Power Co [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Make Whole Premium on Extinguishment of Long-term Debt												0	0	92.7
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		0		0		0
Indiana Michigan Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		0		0		0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges												0	10.5	0
Ohio Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		0		0		0
Public Service Co Of Oklahoma [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		0		0		0
Southwestern Electric Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income			0		0		$ 0		$ 0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges												33.6	0	$ 0
I&M Price River Coal Reserves [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Public Utilities, Property, Plant and Equipment, Net			11										11
Merchant Coal-Fired Generation Assets [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure			0										0
Public Utilities, Property, Plant and Equipment, Net			2,139.4										2,139.4
Asset Impairments and Other Related Charges			3		2,139.4						$ 4
Zimmer Plant Assets [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges											$ 7
Racine Hydroelectric Plant [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure		0										$ 0
Asset Impairments and Other Related Charges		$ 43
Trent and Desert Sky Wind Farms [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure			46										46
Public Utilities, Property, Plant and Equipment, Net			118.7										118.7
Asset Impairments and Other Related Charges					72.7
Coal Reserves [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure			3.8										3.8
Public Utilities, Property, Plant and Equipment, Net	[3]		56.6										56.6
Asset Impairments and Other Related Charges	[3]				52.8
Total Impaired Assets [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure			49.8										49.8
Public Utilities, Property, Plant and Equipment, Net			$ 2,314.7										$ 2,314.7
Asset Impairments and Other Related Charges					$ 2,264.9
[1]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[2]	Includes the transfer of the Wind Farms (see Note 7).
[3]	(a)Includes the $11 million book value of I&M’s Price River Coal Reserves which were fully impaired. This $11 million impairment is reflected in the Vertically Integrated Utilities Segment.

Benefit Plans 1 (Details)

Benefit Plans 1 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		$ 2,553.5	$ 2,085.1
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(830.9)	(774.6)
AEP Texas Inc. [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		114.8	73.3
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(63.4)	(56.3)
Appalachian Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		190	133.3
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(74.7)	(64.5)
Indiana Michigan Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		179.9	121.5
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(88.5)	(120.4)
Ohio Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		374.2	295.5
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(46.2)	(111.7)
Public Service Co Of Oklahoma [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		8.7	10
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(22.5)	(24.8)
Southwestern Electric Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		109.9	99.9
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(19.9)	(9.7)
Pension Plans [Member]
Underfunded Status, Accumulated Benefit Obligation			(88.5)
Defined Benefit Plan, Accumulated Benefit Obligation		$ 5,025.2	$ 4,915.8
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.80%	4.75%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.80%	4.75%	4.80%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 5,085.8	$ 4,992.9
Service Cost		96.5	85.8	$ 93.5
Interest Cost		203.1	211.6	205.3
Actuarial (Gain) Loss		182.4	142.7
Benefit Payments		(352)	(347.2)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		5,215.8	5,085.8	4,992.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		4,827.3	4,767.6
Actual Gain (Loss) on Plan Assets		600	315.5
Company Contributions		98.8	91.4
Participant Contributions		0	0
Benefit Payments		(352)	(347.2)
Fair Value of Plan Assets as of December 31		5,174.1	4,827.3	$ 4,767.6
Funded (Underfunded) Status as of December 31		(41.7)	(258.5)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		36.3	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(6.2)	(5.9)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(71.8)	(252.6)
Funded (Underfunded) Status		(41.7)	(258.5)
Components
Net Actuarial Loss		1,354.2	1,569.8
Prior Service Cost (Credit)		0	1
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(132.8)	107.5
Amortization of Actuarial Gain (Loss)		(82.8)	(83.8)
Amortization of Prior Service Credit (Cost)		(1)	(2.3)
Change for the Year		$ (216.6)	$ 21.4
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.80%	4.75%
Pension Plans [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	$ 11.6	$ 0
Pension Plans [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		1,271.3	1,415.6
Pension Plans [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		17.4	54.4
Pension Plans [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		53.9	100.8
Pension Plans [Member] | AEP Texas Inc. [Member]
Defined Benefit Plan, Accumulated Benefit Obligation		$ 425.2	$ 408.5
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.90%	4.85%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.90%	4.85%	4.50%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 421.7	$ 420.3
Transfer of CSW Energy, Inc. Benefit Obligation		0	(2.8)
Service Cost		8.6	7.5	$ 7.6
Interest Cost		17.1	17.8	17.2
Actuarial (Gain) Loss		25.6	11.1
Benefit Payments		(31.7)	(32.2)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		441.3	421.7	420.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		416.6	415.4
Transfer of CSW Energy, Inc. Plan Assets		0	(2.5)
Actual Gain (Loss) on Plan Assets		61.8	27.4
Company Contributions		9.2	8.5
Participant Contributions		0	0
Benefit Payments		(31.7)	(32.2)
Fair Value of Plan Assets as of December 31		455.9	416.6	$ 415.4
Funded (Underfunded) Status as of December 31		14.6	(5.1)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		18.6	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.4)	(0.4)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(3.6)	(4.7)
Funded (Underfunded) Status		14.6	(5.1)
Components
Net Actuarial Loss		175.2	193.3
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(11.1)	7.1
Amortization of Actuarial Gain (Loss)		(7)	(7.1)
Amortization of Prior Service Credit (Cost)		0	(0.4)
Change for the Year		$ (18.1)	$ (0.4)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.90%	4.85%
Pension Plans [Member] | AEP Texas Inc. [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	$ 2	$ 0
Pension Plans [Member] | AEP Texas Inc. [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		161.4	178.5
Pension Plans [Member] | AEP Texas Inc. [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		2.9	5.2
Pension Plans [Member] | AEP Texas Inc. [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		8.9	9.6
Pension Plans [Member] | Appalachian Power Co [Member]
Underfunded Status, Accumulated Benefit Obligation			(34.9)
Defined Benefit Plan, Accumulated Benefit Obligation		$ 648.2	$ 641.3
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.60%	4.55%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.60%	4.55%	4.45%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 654	$ 653.4
Service Cost		9.4	8.1	$ 8.7
Interest Cost		25.7	27.2	26.7
Actuarial (Gain) Loss		15.7	9.2
Benefit Payments		(39.8)	(43.9)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		665	654	653.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		606.4	603.2
Actual Gain (Loss) on Plan Assets		74.9	38.3
Company Contributions		10.2	8.8
Participant Contributions		0	0
Benefit Payments		(39.8)	(43.9)
Fair Value of Plan Assets as of December 31		651.7	606.4	$ 603.2
Funded (Underfunded) Status as of December 31		(13.3)	(47.6)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(13.3)	(47.6)
Funded (Underfunded) Status		(13.3)	(47.6)
Components
Net Actuarial Loss		182.5	216.2
Prior Service Cost (Credit)		0	0.2
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(23.3)	6.2
Amortization of Actuarial Gain (Loss)		(10.4)	(10.8)
Amortization of Prior Service Credit (Cost)		(0.2)	(0.1)
Change for the Year		$ (33.9)	$ (4.7)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.60%	4.55%
Pension Plans [Member] | Appalachian Power Co [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	$ 0.4	$ 0
Pension Plans [Member] | Appalachian Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		179.9	213.7
Pension Plans [Member] | Appalachian Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		0.5	1
Pension Plans [Member] | Appalachian Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		1.7	1.7
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Underfunded Status, Accumulated Benefit Obligation			(2.7)
Defined Benefit Plan, Accumulated Benefit Obligation		$ 592.8	$ 588.8
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.85%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.85%	4.80%	4.80%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 611.6	$ 591.5
Service Cost		14	12.2	$ 12.9
Interest Cost		24.3	25.3	24.5
Actuarial (Gain) Loss		10.8	20.1
Benefit Payments		(36.4)	(37.5)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		624.3	611.6	591.5
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		586.1	570
Actual Gain (Loss) on Plan Assets		74	40.6
Company Contributions		13	13
Participant Contributions		0	0
Benefit Payments		(36.4)	(37.5)
Fair Value of Plan Assets as of December 31		636.7	586.1	$ 570
Funded (Underfunded) Status as of December 31		12.4	(25.5)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		13.4	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(1)	(25.5)
Funded (Underfunded) Status		12.4	(25.5)
Components
Net Actuarial Loss		94.9	133.2
Prior Service Cost (Credit)		0	0.2
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(28.6)	13.2
Amortization of Actuarial Gain (Loss)		(9.7)	(10)
Amortization of Prior Service Credit (Cost)		(0.2)	(0.1)
Change for the Year		$ (38.5)	$ 3.1
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.85%	4.80%
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	$ 0.4	$ 0
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		91.8	128.2
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		0.7	1.8
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		2	3.4
Pension Plans [Member] | Ohio Power Co [Member]
Underfunded Status, Accumulated Benefit Obligation			(4.2)
Defined Benefit Plan, Accumulated Benefit Obligation		$ 483.5	$ 478
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.95%	4.85%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.95%	4.85%	4.80%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 492.9	$ 497.5
Service Cost		7.5	6.5	$ 6.7
Interest Cost		19.4	20.6	20.3
Actuarial (Gain) Loss		13.1	4.7
Benefit Payments		(31.8)	(36.4)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		501.1	492.9	497.5
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		473.8	472.1
Actual Gain (Loss) on Plan Assets		58.9	30.9
Company Contributions		8.2	7.2
Participant Contributions		0	0
Benefit Payments		(31.8)	(36.4)
Fair Value of Plan Assets as of December 31		509.1	473.8	$ 472.1
Funded (Underfunded) Status as of December 31		8	(19.1)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		8.4	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(0.4)	(19.1)
Funded (Underfunded) Status		8	(19.1)
Components
Net Actuarial Loss		189.6	215.4
Prior Service Cost (Credit)		0	0.1
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(18)	1.5
Amortization of Actuarial Gain (Loss)		(7.8)	(8.1)
Amortization of Prior Service Credit (Cost)		(0.1)	(0.1)
Change for the Year		$ (25.9)	$ (6.7)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.95%	4.85%
Pension Plans [Member] | Ohio Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 189.6	$ 215.5
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Defined Benefit Plan, Accumulated Benefit Obligation		$ 259.6	$ 254.2
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.90%	4.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.90%	4.90%	4.80%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 266.7	$ 265.4
Service Cost		6.4	6.2	$ 6.4
Interest Cost		10.7	11.2	10.9
Actuarial (Gain) Loss		10.1	3.1
Benefit Payments		(17.3)	(19.2)
Participant Contributions		0	0
Benefit Obligation as of December 31		276.6	266.7	265.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		266	262.1
Actual Gain (Loss) on Plan Assets		33.6	17.3
Company Contributions		5.5	5.8
Participant Contributions		0	0
Benefit Payments		(17.3)	(19.2)
Fair Value of Plan Assets as of December 31		287.8	266	$ 262.1
Funded (Underfunded) Status as of December 31		11.2	(0.7)
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		13.9	1.6
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.2)	(0.2)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(2.5)	(2.1)
Funded (Underfunded) Status		11.2	(0.7)
Components
Net Actuarial Loss		78.8	91
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(7.9)	1.3
Amortization of Actuarial Gain (Loss)		(4.3)	(4.4)
Amortization of Prior Service Credit (Cost)		0	(0.3)
Change for the Year		$ (12.2)	$ (3.4)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.90%	4.90%
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 78.8	$ 91
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Defined Benefit Plan, Accumulated Benefit Obligation		$ 291.6	$ 281.5
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.65%	4.05%
Rate of Compensation Increase	[1]	4.80%	4.75%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.05%	4.30%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.80%	4.75%	4.80%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 296.6	$ 282.8
Service Cost		8.7	8.1	$ 8.3
Interest Cost		12.3	12.4	11.8
Actuarial (Gain) Loss		16.3	13.8
Benefit Payments		(19.3)	(20.5)
Participant Contributions		0	0
Benefit Obligation as of December 31		314.6	296.6	282.8
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		287.3	280.6
Actual Gain (Loss) on Plan Assets		34.6	18.8
Company Contributions		9.1	8.4
Participant Contributions		0	0
Benefit Payments		(19.3)	(20.5)
Fair Value of Plan Assets as of December 31		311.7	287.3	$ 280.6
Funded (Underfunded) Status as of December 31		(2.9)	(9.3)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.2)	(0.1)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(2.7)	(9.2)
Funded (Underfunded) Status		(2.9)	(9.3)
Components
Net Actuarial Loss		97.4	103.8
Prior Service Cost (Credit)		0	0.1
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(1.5)	11.5
Amortization of Actuarial Gain (Loss)		(4.9)	(4.8)
Amortization of Prior Service Credit (Cost)		(0.1)	(0.3)
Change for the Year		$ (6.5)	$ 6.4
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.80%	4.75%
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	$ 0	$ 0
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		97.4	103.9
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		0	0
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 0	$ 0
Pension Plans [Member] | Minimum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Maximum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Other Postretirement Benefit Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 2.5
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(2)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		45.4
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(39.6)
Change in Benefit Obligation
Benefit Obligation as of January 1		1,447.4	$ 1,450.6
Service Cost		11.2	10.2	$ 12.2
Interest Cost		59.3	60.9	56.8
Actuarial (Gain) Loss		(97.5)	17.3
Benefit Payments		(128.6)	(130.2)
Participant Contributions		39.5	37.8
Medicare Subsidy		0.7	0.8
Benefit Obligation as of December 31		1,332	1,447.4	1,450.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		1,545.9	1,577.4
Actual Gain (Loss) on Plan Assets		271.6	56
Company Contributions		4.1	4.9
Participant Contributions		39.5	37.8
Benefit Payments		(128.6)	(130.2)
Fair Value of Plan Assets as of December 31		1,732.5	1,545.9	$ 1,577.4
Funded (Underfunded) Status as of December 31		400.5	98.5
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		463	154.5
Other Current Liabilities - Accrued Short-term Benefit Liability		(3.2)	(3)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(59.3)	(53)
Funded (Underfunded) Status		400.5	98.5
Components
Net Actuarial Loss		309.9	614.4
Prior Service Cost (Credit)		(416.3)	(485.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(267.8)	68.4
Amortization of Actuarial Gain (Loss)		(36.7)	(31.4)
Amortization of Prior Service Credit (Cost)		69.1	69
Change for the Year		(235.4)	106
Other Postretirement Benefit Plans [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	(3.4)	0
Other Postretirement Benefit Plans [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(82.4)	90.4
Other Postretirement Benefit Plans [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(5)	13.5
Other Postretirement Benefit Plans [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (15.6)	$ 25.1
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		2.6
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(2.4)
Change in Benefit Obligation
Benefit Obligation as of January 1		120.4	$ 122
Transfer of CSW Energy, Inc. Benefit Obligation		0	(0.4)
Service Cost		0.9	0.7	$ 0.8
Interest Cost		4.9	5.1	4.8
Actuarial (Gain) Loss		(11.9)	0.8
Benefit Payments		(10.8)	(11.4)
Participant Contributions		3.6	3.5
Medicare Subsidy		0	0.1
Benefit Obligation as of December 31		107.1	120.4	122
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		134.1	138.6
Transfer of CSW Energy, Inc. Plan Assets		0	(0.4)
Actual Gain (Loss) on Plan Assets		20.4	3.8
Company Contributions		0	0
Participant Contributions		3.6	3.5
Benefit Payments		(10.8)	(11.4)
Fair Value of Plan Assets as of December 31		147.3	134.1	$ 138.6
Funded (Underfunded) Status as of December 31		40.2	13.7
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		40.2	13.7
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		40.2	13.7
Components
Net Actuarial Loss		23.9	50.7
Prior Service Cost (Credit)		(35.4)	(41.2)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(23.6)	6.4
Amortization of Actuarial Gain (Loss)		(3.2)	(2.8)
Amortization of Prior Service Credit (Cost)		5.8	6
Change for the Year		(21)	9.6
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	(0.2)	0
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(10.2)	9.7
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(0.3)	(0.1)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (0.8)	$ (0.1)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.5
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.4)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		10.8
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(9.1)
Change in Benefit Obligation
Benefit Obligation as of January 1		255.6	$ 262.2
Service Cost		1.1	1	$ 1.1
Interest Cost		10.6	10.8	10.3
Actuarial (Gain) Loss		(13.4)	(0.2)
Benefit Payments		(24.3)	(24.8)
Participant Contributions		6.7	6.4
Medicare Subsidy		0.2	0.2
Benefit Obligation as of December 31		236.5	255.6	262.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		246.9	256.7
Actual Gain (Loss) on Plan Assets		41.6	5.9
Company Contributions		2.5	2.7
Participant Contributions		6.7	6.4
Benefit Payments		(24.3)	(24.8)
Fair Value of Plan Assets as of December 31		273.4	246.9	$ 256.7
Funded (Underfunded) Status as of December 31		36.9	(8.7)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		74.6	25.2
Other Current Liabilities - Accrued Short-term Benefit Liability		(2.5)	(2.4)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(35.2)	(31.5)
Funded (Underfunded) Status		36.9	(8.7)
Components
Net Actuarial Loss		48	92.9
Prior Service Cost (Credit)		(60.4)	(70.5)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(38.6)	11.4
Amortization of Actuarial Gain (Loss)		(6.3)	(5.4)
Amortization of Prior Service Credit (Cost)		10.1	10.1
Change for the Year		(34.8)	16.1
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	(0.2)	0
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(11.1)	7.7
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(0.3)	5.1
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (0.8)	$ 9.6
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.2
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.2)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		3.7
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(3.4)
Change in Benefit Obligation
Benefit Obligation as of January 1		167.6	$ 166.3
Service Cost		1.6	1.5	$ 1.6
Interest Cost		6.9	7	6.4
Actuarial (Gain) Loss		(12)	3.8
Benefit Payments		(15.6)	(15.7)
Participant Contributions		4.9	4.6
Medicare Subsidy		0.1	0.1
Benefit Obligation as of December 31		153.5	167.6	166.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		186.6	189
Actual Gain (Loss) on Plan Assets		35.2	8.7
Company Contributions		0	0
Participant Contributions		4.9	4.6
Benefit Payments		(15.6)	(15.7)
Fair Value of Plan Assets as of December 31		211.1	186.6	$ 189
Funded (Underfunded) Status as of December 31		57.6	19
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		57.6	19
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		57.6	19
Components
Net Actuarial Loss		42	81.3
Prior Service Cost (Credit)		(56.9)	(66.3)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(34.9)	7.9
Amortization of Actuarial Gain (Loss)		(4.4)	(3.7)
Amortization of Prior Service Credit (Cost)		9.4	9.4
Change for the Year		(29.9)	13.6
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	(0.1)	0
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(14)	13.7
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(0.2)	0.5
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (0.6)	$ 0.8
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.2
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.2)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		3.5
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(3.2)
Change in Benefit Obligation
Benefit Obligation as of January 1		164	$ 168.6
Service Cost		0.9	0.8	$ 0.9
Interest Cost		6.7	7	6.4
Actuarial (Gain) Loss		(16.6)	(1)
Benefit Payments		(15.5)	(16.2)
Participant Contributions		4.7	4.7
Medicare Subsidy		0.1	0.1
Benefit Obligation as of December 31		144.3	164	168.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		182.6	191.6
Actual Gain (Loss) on Plan Assets		26.7	2.5
Company Contributions		0	0
Participant Contributions		4.7	4.7
Benefit Payments		(15.5)	(16.2)
Fair Value of Plan Assets as of December 31		198.5	182.6	$ 191.6
Funded (Underfunded) Status as of December 31		54.2	18.6
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		54.2	18.6
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		54.2	18.6
Components
Net Actuarial Loss		22.6	58.2
Prior Service Cost (Credit)		(41.6)	(48.5)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(31.3)	9.4
Amortization of Actuarial Gain (Loss)		(4.3)	(3.8)
Amortization of Prior Service Credit (Cost)		6.9	6.9
Change for the Year		(28.7)	12.5
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (19)	$ 9.7
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		1.7
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(1.5)
Change in Benefit Obligation
Benefit Obligation as of January 1		77.6	$ 77.7
Service Cost		0.7	0.6	$ 0.7
Interest Cost		3.2	3.3	3
Actuarial (Gain) Loss		(7.5)	1
Benefit Payments		(6.9)	(7.2)
Participant Contributions		2.3	2.2
Benefit Obligation as of December 31		69.4	77.6	77.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		86.4	88.3
Actual Gain (Loss) on Plan Assets		13.7	3.1
Company Contributions		0	0
Participant Contributions		2.3	2.2
Benefit Payments		(6.9)	(7.2)
Fair Value of Plan Assets as of December 31		95.5	86.4	$ 88.3
Funded (Underfunded) Status as of December 31		26.1	8.8
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		26.1	8.8
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		26.1	8.8
Components
Net Actuarial Loss		19.8	37.3
Prior Service Cost (Credit)		(25.9)	(30.2)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(15.5)	3.9
Amortization of Actuarial Gain (Loss)		(2)	(1.8)
Amortization of Prior Service Credit (Cost)		4.3	4.3
Change for the Year		(13.2)	6.4
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (6.1)	$ 7.1
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		3.60%	4.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.10%	4.30%	4.00%
Expected Return on Plan Assets		6.75%	7.00%	6.75%
Health Care Trend Rates
Initial		6.50%	7.00%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		1.9
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(1.8)
Change in Benefit Obligation
Benefit Obligation as of January 1		86.9	$ 86.1
Service Cost		0.9	0.8	$ 0.8
Interest Cost		3.6	3.6	3.4
Actuarial (Gain) Loss		(6.2)	1.5
Benefit Payments		(7.4)	(7.5)
Participant Contributions		2.5	2.4
Benefit Obligation as of December 31		80.3	86.9	86.1
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		96.8	97.8
Actual Gain (Loss) on Plan Assets		18.5	4.1
Company Contributions		0	0
Participant Contributions		2.5	2.4
Benefit Payments		(7.4)	(7.5)
Fair Value of Plan Assets as of December 31		110.4	96.8	$ 97.8
Funded (Underfunded) Status as of December 31		30.1	9.9
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		30.1	9.9
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		30.1	9.9
Components
Net Actuarial Loss		24.7	45.4
Prior Service Cost (Credit)		(31.4)	(36.6)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(18.4)	4
Amortization of Actuarial Gain (Loss)		(2.3)	(1.9)
Amortization of Prior Service Credit (Cost)		5.2	5
Change for the Year		(15.5)	7.1
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[3]	(0.4)	0
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(3.7)	5.7
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(0.6)	1.1
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (2)	$ 2
[1]	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
[2]	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
[3]	Amounts relate to the re-measurement of Deferred Income Taxes as a result of Tax Reform. In accordance with the accounting guidance for “Income Taxes”, re-measurement of Deferred Income Taxes related to AOCI must flow through the statement of income.

Benefit Plans 2 (Details)

Benefit Plans 2 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2017		Dec. 31, 2016
Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4,827.3		$ 4,767.6		$ 5,174.1		$ 4,827.3
Year End Allocation
Total						100.00%		100.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		4,827.3		4,767.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		5,174.1		4,827.3
Pension Plan [Member] | AEP Texas Inc. [Member]
Allocated Assets of Investments						8.80%		8.60%
Pension and Other Postretirement Plans' Assets
Asset Class		416.6		415.4		$ 455.9		$ 416.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		416.6		415.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		455.9		416.6
Pension Plan [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments						12.60%		12.60%
Pension and Other Postretirement Plans' Assets
Asset Class		606.4		603.2		$ 651.7		$ 606.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		606.4		603.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		651.7		606.4
Pension Plan [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments						12.30%		12.10%
Pension and Other Postretirement Plans' Assets
Asset Class		586.1		570		$ 636.7		$ 586.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		586.1		570
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		636.7		586.1
Pension Plan [Member] | Ohio Power Co [Member]
Allocated Assets of Investments						9.80%		9.80%
Pension and Other Postretirement Plans' Assets
Asset Class		473.8		472.1		$ 509.1		$ 473.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		473.8		472.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		509.1		473.8
Pension Plan [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments						5.60%		5.50%
Pension and Other Postretirement Plans' Assets
Asset Class		266		262.1		$ 287.8		$ 266
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		266		262.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		287.8		266
Pension Plan [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments						6.00%		6.00%
Pension and Other Postretirement Plans' Assets
Asset Class		287.3		280.6		$ 311.7		$ 287.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		287.3		280.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		311.7		287.3
Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,545.9		1,577.4		$ 1,732.5		$ 1,545.9
Year End Allocation
Total						100.00%		100.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		1,545.9		1,577.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,732.5		1,545.9
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Allocated Assets of Investments						8.50%		8.70%
Pension and Other Postretirement Plans' Assets
Asset Class		134.1		138.6		$ 147.3		$ 134.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		134.1		138.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		147.3		134.1
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments						15.80%		16.00%
Pension and Other Postretirement Plans' Assets
Asset Class		246.9		256.7		$ 273.4		$ 246.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		246.9		256.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		273.4		246.9
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments						12.20%		12.10%
Pension and Other Postretirement Plans' Assets
Asset Class		186.6		189		$ 211.1		$ 186.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		186.6		189
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		211.1		186.6
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Allocated Assets of Investments						11.50%		11.80%
Pension and Other Postretirement Plans' Assets
Asset Class		182.6		191.6		$ 198.5		$ 182.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		182.6		191.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		198.5		182.6
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments						5.50%		5.60%
Pension and Other Postretirement Plans' Assets
Asset Class		86.4		88.3		$ 95.5		$ 86.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		86.4		88.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		95.5		86.4
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments						6.40%		6.30%
Pension and Other Postretirement Plans' Assets
Asset Class		96.8		97.8		$ 110.4		$ 96.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		96.8		97.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		110.4		96.8
Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		365		365		790.8		365
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		365
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		790.8		365
Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		318.9		318.9		339.9		318.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		318.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		339.9		318.9
Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		797		797		826.7		797
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		797
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		826.7		797
Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		976.6		976.6		700.4		976.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		976.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		700.4		976.6
Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,941.7		2,941.7		3,556.6		2,941.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		2,941.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		3,556.6		2,941.7
Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		250.4		250.4		692.2		250.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		250.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		692.2		250.4
Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		723.6		674.5		0		723.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		723.6		674.5
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		0		24.9
Relating to Assets Sold During the Period		0		45.2
Purchases and Sales		0		(21)
Transfers into Level 3		0		0
Transfers out of Level 3		(723.6)	[1]	0
Fair Value of Plan Assets as of December 31		0		723.6
Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Equity Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,231.5		1,231.5		$ 1,306.1		$ 1,231.5
Year End Allocation
Total						25.20%		25.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		1,231.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,306.1		1,231.5
Equity Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		999.2		999.2		$ 777		$ 999.2
Year End Allocation
Total						44.80%		64.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		999.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		777		999.2
Equity Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		400.5		400.5		$ 452.9		$ 400.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		400.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		452.9		400.5
Equity Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		20.5		20.5		153.6		20.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		20.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		153.6		20.5
Equity Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		797		797		826.3		797
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		797
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		826.3		797
Equity Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		952.6		952.6		614		952.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		952.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		614		952.6
Equity Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		34		34		26.9		34
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		34
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		26.9		34
Equity Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		26.1		26.1		9.4		26.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		26.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		9.4		26.1
Equity Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Equity Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Domestic [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		357.8		357.8		$ 318.6		$ 357.8
Year End Allocation
Total						6.20%		7.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		357.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		318.6		357.8
Domestic [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		517.1		517.1		$ 307.1		$ 517.1
Year End Allocation
Total						17.70%		33.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		517.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		307.1		517.1
Domestic [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 0		$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Domestic [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Domestic [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		357.8		357.8		318.6		357.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		357.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		318.6		357.8
Domestic [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		517.1		517.1		307.1		517.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		517.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		307.1		517.1
Domestic [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Domestic [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Domestic [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Domestic [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		439.2		439.2		$ 507.7		$ 439.2
Year End Allocation
Total						9.80%		9.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		439.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		507.7		439.2
International [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		435.5		435.5		$ 306.9		$ 435.5
Year End Allocation
Total						17.70%		28.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		435.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		306.9		435.5
International [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 0		$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		439.2		439.2		507.7		439.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		439.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		507.7		439.2
International [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		435.5		435.5		306.9		435.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		435.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		306.9		435.5
International [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Options [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		20		20		$ 26.9		$ 20
Year End Allocation
Total						0.50%		0.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		20
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		26.9		20
Options [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		15.2		15.2		$ 9.4		$ 15.2
Year End Allocation
Total						0.50%		1.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		15.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		9.4		15.2
Options [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 0		$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Options [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Options [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Options [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Options [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		20		20		26.9		20
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		20
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		26.9		20
Options [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		15.2		15.2		9.4		15.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		15.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		9.4		15.2
Options [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Options [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Common Collective Trusts [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	414.5		414.5		$ 452.9		$ 414.5
Year End Allocation
Total	[2]					8.70%		8.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	414.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	452.9		414.5
Common Collective Trusts [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	31.4		31.4		$ 153.6		$ 31.4
Year End Allocation
Total	[3]					8.90%		2.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	31.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	153.6		31.4
Common Collective Trusts [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	400.5		400.5		$ 452.9		$ 400.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	400.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	452.9		400.5
Common Collective Trusts [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	20.5		20.5		153.6		20.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	20.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	153.6		20.5
Common Collective Trusts [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0		0
Common Collective Trusts [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0		0
Common Collective Trusts [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	14		14		0		14
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	14
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0		14
Common Collective Trusts [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	10.9		10.9		0		10.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	10.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0		10.9
Common Collective Trusts [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0		0
Common Collective Trusts [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0		0
Fixed Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,825.6		2,825.6		$ 2,992.3		$ 2,825.6
Year End Allocation
Total						57.80%		58.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		2,825.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		2,992.3		2,825.6
Fixed Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		307.5		307.5		$ 693.9		$ 307.5
Year End Allocation
Total						40.10%		19.90%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		307.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		693.9		307.5
Fixed Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		79.5		79.5		$ 0		$ 79.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		79.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		79.5
Fixed Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		93.7		93.7		185		93.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		93.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		185		93.7
Fixed Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Fixed Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		49.7		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		49.7		0
Fixed Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,746.1		2,746.1		2,992.3		2,746.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		2,746.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		2,992.3		2,746.1
Fixed Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		213.8		213.8		459.2		213.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		213.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		459.2		213.8
Fixed Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Fixed Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Common Collective Trust - Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	32.3		32.3				$ 32.3
Year End Allocation
Total	[2]							0.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	32.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]			32.3
Common Collective Trust - Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	93.7		93.7		$ 185		$ 93.7
Year End Allocation
Total	[3]					10.70%		6.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	93.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	185		93.7
Common Collective Trust - Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	32.3		32.3				$ 32.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	32.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]			32.3
Common Collective Trust - Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	93.7		93.7		$ 185		93.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	93.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	185		93.7
Common Collective Trust - Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0				0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]			0
Common Collective Trust - Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0		0
Common Collective Trust - Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0				0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]			0
Common Collective Trust - Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0		0
Common Collective Trust - Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0				0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]			0
Common Collective Trust - Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0		0
United States Government and Agency Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		441	[2]	441	[2]	$ 1,376.5		$ 441	[2]
Year End Allocation
Total						26.60%		9.10%	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	441
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,376.5		441	[2]
United States Government and Agency Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		64.7		64.7		$ 187.4		$ 64.7
Year End Allocation
Total						10.80%		4.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		64.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		187.4		64.7
United States Government and Agency Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		17.7	[2]	17.7	[2]	$ 0		$ 17.7	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	17.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		17.7	[2]
United States Government and Agency Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
United States Government and Agency Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
United States Government and Agency Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
United States Government and Agency Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		423.3	[2]	423.3	[2]	1,376.5		423.3	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	423.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,376.5		423.3	[2]
United States Government and Agency Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		64.7		64.7		187.4		64.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		64.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		187.4		64.7
United States Government and Agency Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
United States Government and Agency Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Corporate Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,942.2	[2]	1,942.2	[2]	$ 1,277		$ 1,942.2	[2]
Year End Allocation
Total						24.70%		40.20%	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	1,942.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,277		1,942.2	[2]
Corporate Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		121.6		121.6		$ 214.1		$ 121.6
Year End Allocation
Total						12.40%		7.90%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		121.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		214.1		121.6
Corporate Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		10	[2]	10	[2]	$ 0		$ 10	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	10
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		10	[2]
Corporate Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Corporate Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
Corporate Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Corporate Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,932.2	[2]	1,932.2	[2]	1,277		1,932.2	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	1,932.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,277		1,932.2	[2]
Corporate Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		121.6		121.6		214.1		121.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		121.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		214.1		121.6
Corporate Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
Corporate Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Foreign Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		385.8	[2]	385.8	[2]	$ 296.9		$ 385.8	[2]
Year End Allocation
Total						5.70%		8.00%	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	385.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		296.9		385.8	[2]
Foreign Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		18.6		18.6		$ 40.7		$ 18.6
Year End Allocation
Total						2.40%		1.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		18.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		40.7		18.6
Foreign Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		12.1	[2]	12.1	[2]	$ 0		$ 12.1	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	12.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		12.1	[2]
Foreign Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Foreign Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
Foreign Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Foreign Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		373.7	[2]	373.7	[2]	296.9		373.7	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	373.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		296.9		373.7	[2]
Foreign Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		18.6		18.6		40.7		18.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		18.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		40.7		18.6
Foreign Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0.1		0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0	[2]	0.1
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date				0
Relating to Assets Sold During the Period				0
Purchases and Sales				(0.1)
Transfers into Level 3				0
Transfers out of Level 3				0
Fair Value of Plan Assets as of December 31		0		0	[2]
Foreign Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
State and Local Government [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		11.5		11.5		$ 31.7		$ 11.5
Year End Allocation
Total						0.60%		0.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		11.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		31.7		11.5
State and Local Government [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		3		3		$ 66.5		$ 3
Year End Allocation
Total						3.80%		0.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		66.5		3
State and Local Government [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 0		$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
State and Local Government [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
State and Local Government [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
State and Local Government [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		49.7		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		49.7		0
State and Local Government [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		11.5		11.5		31.7		11.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		11.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		31.7		11.5
State and Local Government [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		3		3		16.8		3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		16.8		3
State and Local Government [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
State and Local Government [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Other - Asset Backed [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		12.8	[2]	12.8	[2]	$ 10.2		$ 12.8	[2]
Year End Allocation
Total						0.20%		0.30%	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	12.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		10.2		12.8	[2]
Other - Asset Backed [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		5.9		5.9		$ 0.2		$ 5.9
Year End Allocation
Total						0.00%		0.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		5.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0.2		5.9
Other - Asset Backed [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		7.4	[2]	7.4	[2]	$ 0		$ 7.4	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	7.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		7.4	[2]
Other - Asset Backed [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Other - Asset Backed [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
Other - Asset Backed [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Other - Asset Backed [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		5.4	[2]	5.4	[2]	10.2		5.4	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	5.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		10.2		5.4	[2]
Other - Asset Backed [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		5.9		5.9		0.2		5.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		5.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0.2		5.9
Other - Asset Backed [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[2]	0	[2]	0		0	[2]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[2]
Other - Asset Backed [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Infrastructure [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		57.6		57.6		$ 59.5	[2]	$ 57.6
Year End Allocation
Total						1.20%	[2]	1.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		57.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		59.5	[2]	57.6
Infrastructure [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 59.5	[2]	$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		59.5	[2]	0
Infrastructure [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[2]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[2]	0
Infrastructure [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[2]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[2]	0
Infrastructure [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		57.6		42		0	[2]	57.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		57.6		42
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		0		5.9
Relating to Assets Sold During the Period		0		0.9
Purchases and Sales		0		8.8
Transfers into Level 3		0		0
Transfers out of Level 3		(57.6)	[1]	0
Fair Value of Plan Assets as of December 31		0	[2]	57.6
Real Estate [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		254.9		254.9		$ 290.3	[2]	$ 254.9
Year End Allocation
Total						5.60%	[2]	5.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		254.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		290.3	[2]	254.9
Real Estate [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 290.3	[2]	$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		290.3	[2]	0
Real Estate [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[2]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[2]	0
Real Estate [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[2]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[2]	0
Real Estate [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		254.9		253.7		0	[2]	254.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		254.9		253.7
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		0		5.3
Relating to Assets Sold During the Period		0		23.2
Purchases and Sales		0		(27.3)
Transfers into Level 3		0		0
Transfers out of Level 3		(254.9)	[1]	0
Fair Value of Plan Assets as of December 31		0	[2]	254.9
Alternative Investments [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		411.1		411.1		$ 446	[2]	$ 411.1
Year End Allocation
Total						8.60%	[2]	8.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		411.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		446	[2]	411.1
Alternative Investments [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 446	[2]	$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		446	[2]	0
Alternative Investments [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[2]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[2]	0
Alternative Investments [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[2]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[2]	0
Alternative Investments [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		411.1		378.7		0	[2]	411.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		411.1		378.7
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		0		13.7
Relating to Assets Sold During the Period		0		21.1
Purchases and Sales		0		(2.4)
Transfers into Level 3		0		0
Transfers out of Level 3		(411.1)	[1]	0
Fair Value of Plan Assets as of December 31		0	[2]	411.1
Securities Lending [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		161.6		161.6		$ 501.8		$ 161.6
Year End Allocation
Total						9.70%		3.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		161.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		501.8		161.6
Securities Lending [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		$ 0		$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Securities Lending [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Securities Lending [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		161.6		161.6		501.8		161.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		161.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		501.8		161.6
Securities Lending [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Securities Lending Collateral [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	(163.3)		(163.3)		$ (503.5)		$ (163.3)
Year End Allocation
Total	[4]					(9.70%)		(3.40%)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[4]	(163.3)
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	(503.5)		(163.3)
Securities Lending Collateral [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	(163.3)		(163.3)		$ (503.5)		$ (163.3)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[4]	(163.3)
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	(503.5)		(163.3)
Securities Lending Collateral [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[4]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0		0
Securities Lending Collateral [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[4]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0		0
Securities Lending Collateral [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[4]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0		0
Trusted Owned Life Insurance [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		207.5		207.5		$ 223.6		$ 207.5
Year End Allocation
Total						12.90%		13.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		207.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		223.6		207.5
Trusted Owned Life Insurance [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		207.5		207.5		$ 0		$ 207.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		207.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		207.5
Trusted Owned Life Insurance [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
Trusted Owned Life Insurance [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		223.6		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		223.6		0
Trusted Owned Life Insurance [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0
International Equities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		110.1	[3]	110.1	[3]	$ 105.4		$ 110.1	[3]
Year End Allocation
Total						6.10%		7.10%	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	110.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		105.4		110.1	[3]
International Equities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		110.1	[3]	110.1	[3]	$ 0		$ 110.1	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	110.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		110.1	[3]
International Equities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[3]	0	[3]	0		0	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[3]
International Equities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[3]	0	[3]	105.4		0	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		105.4		0	[3]
International Equities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[3]	0	[3]	0		0	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[3]
United States Bonds [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		97.4	[3]	97.4	[3]	$ 118.2		$ 97.4	[3]
Year End Allocation
Total						6.80%		6.30%	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	97.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		118.2		97.4	[3]
United States Bonds [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		97.4	[3]	97.4	[3]	$ 0		$ 97.4	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	97.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		97.4	[3]
United States Bonds [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[3]	0	[3]	0		0	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[3]
United States Bonds [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[3]	0	[3]	118.2		0	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		118.2		0	[3]
United States Bonds [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[3]	0	[3]	0		0	[3]
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[3]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0		0	[3]
Cash and Cash Equivalents [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	29.7		29.7		$ 57.2		$ 29.7
Year End Allocation
Total	[2]					1.10%		0.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	29.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	57.2		29.7
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		34.5		34.5		$ 40.9	[3]	$ 34.5
Year End Allocation
Total						2.40%	[3]	2.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		34.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		40.9	[3]	34.5
Cash and Cash Equivalents [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	29.7		29.7		$ 21.2		$ 29.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	29.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	21.2		29.7
Cash and Cash Equivalents [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		4.2	[3]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		4.2	[3]	0
Cash and Cash Equivalents [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0		0.4		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0.4		0
Cash and Cash Equivalents [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		24		24		36.7	[3]	24
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		24
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		36.7	[3]	24
Cash and Cash Equivalents [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0		35.6		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	35.6		0
Cash and Cash Equivalents [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		10.5		10.5		0	[3]	10.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		10.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[3]	10.5
Cash and Cash Equivalents [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[2]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0		0
Cash and Cash Equivalents [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0		0	[3]	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0	[3]	0
Other - Pending Transactions and Accrued Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	18.6		18.6		$ 24.4		$ 18.6
Year End Allocation
Total	[5]					0.50%		0.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[5]	18.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	24.4		18.6
Other - Pending Transactions and Accrued Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	(2.8)		(2.8)		$ (2.9)		$ (2.8)
Year End Allocation
Total	[6]					(0.20%)		(0.20%)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[6]	(2.8)
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	(2.9)		(2.8)
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	18.6		18.6		$ 24.4		$ 18.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[5]	18.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	24.4		18.6
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	(2.8)		(2.8)		(2.9)		(2.8)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[6]	(2.8)
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	(2.9)		(2.8)
Other - Pending Transactions and Accrued Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[5]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[6]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[5]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[6]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[5]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0		$ 0		$ 0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Fair Value of Plan Assets as of January 1	[6]	0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	$ 0		$ 0
[1]	The classification of Level 3 assets from the prior year was corrected in the current year presentation and included within the fair value hierarchy table as of December 31, 2017 as “Other” investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). Management concluded that these disclosure errors were immaterial individually and in the aggregate to all prior periods presented.
[2]	Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
[3]	Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
[4]	Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.
[5]	Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
[6]	Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Benefit Plans 3 (Details)

Benefit Plans 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 74.6	$ 72.9	$ 73.6
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Multiemployer Plan Surcharge		10.00%	5.00%
Multiemployer Plans Withdrawal Obligation	$ 19	$ 39
Noncurrent Regulatory Assets	3,587.6	5,625.5
UMWA Withdrawal Obligation [Member]
Benefit Plans Textuals [Abstract]
Noncurrent Regulatory Assets	1	20
AEP Texas Inc. [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 6	5.2	$ 5
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 378.7	347.2
Appalachian Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 7.4	7.3	7.2
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 573.9	1,121.1
Indiana Michigan Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 10.7	10.9	10.6
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 579.4	916.6
Ohio Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 6.1	5.6	5.4
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 652.8	1,107.5
Public Service Co Of Oklahoma [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5	4.3	4.2
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 368.1	340.2
Southwestern Electric Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 6	5.7	5.7
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 220.6	551.2
Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	5,025.2	4,915.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	5,215.8	5,085.8	4,992.9
Accumulated Benefit Obligation	5,025.2	4,915.8
Fair Value of Plan Assets	5,174.1	4,827.3	4,767.6
Underfunded Status, Accumulated Benefit Obligation		(88.5)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	100.7
Components of Net Periodic Benefit Cost
Service Cost	96.5	85.8	93.5
Interest Cost	203.1	211.6	205.3
Expected Return on Plan Assets	(284.8)	(280.3)	(274.8)
Amortization of Prior Service Cost (Credit)	1	2.3	2.2
Amortization of Net Actuarial Loss	82.8	83.8	107.1
Net Periodic Benefit Cost (Credit)	98.6	103.2	133.3
Capitalized Portion	(39.9)	(37.8)	(48.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	58.7	65.4	84.9
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	85.5
Total Estimated 2018 Amortization	85.5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	85.5
Pension Plans [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	333.2
2,019	340.1
2,020	345
2,021	356.2
2,022	356.8
Years 2023 to 2027, in Total	1,795.4
Pension Plans [Member] | AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	425.2	408.5
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	441.3	421.7	420.3
Accumulated Benefit Obligation	425.2	408.5
Fair Value of Plan Assets	455.9	416.6	415.4
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	3.6
Components of Net Periodic Benefit Cost
Service Cost	8.6	7.5	7.6
Interest Cost	17.1	17.8	17.2
Expected Return on Plan Assets	(25)	(24.5)	(24.1)
Amortization of Prior Service Cost (Credit)	0	0.4	0.3
Amortization of Net Actuarial Loss	7	7.1	9
Net Periodic Benefit Cost (Credit)	7.7	8.3	10
Capitalized Portion	(4)	(3.6)	(4.7)
Net Periodic Benefit Cost (Credit) Recognized in Expense	3.7	4.7	5.3
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	7.2
Total Estimated 2018 Amortization	7.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	7.2
Pension Plans [Member] | AEP Texas Inc. [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	31
2,019	31
2,020	33.7
2,021	34.7
2,022	33.5
Years 2023 to 2027, in Total	165.6
Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	648.2	641.3
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	665	654	653.4
Accumulated Benefit Obligation	648.2	641.3
Fair Value of Plan Assets	651.7	606.4	603.2
Underfunded Status, Accumulated Benefit Obligation		(34.9)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	9.6
Components of Net Periodic Benefit Cost
Service Cost	9.4	8.1	8.7
Interest Cost	25.7	27.2	26.7
Expected Return on Plan Assets	(35.8)	(35.3)	(35)
Amortization of Prior Service Cost (Credit)	0.2	0.1	0.2
Amortization of Net Actuarial Loss	10.4	10.8	13.9
Net Periodic Benefit Cost (Credit)	9.9	10.9	14.5
Capitalized Portion	(4)	(4.1)	(5.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	5.9	6.8	9
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	10.8
Total Estimated 2018 Amortization	10.8
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	10.8
Pension Plans [Member] | Appalachian Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	42.9
2,019	43.9
2,020	43.5
2,021	44.4
2,022	44.6
Years 2023 to 2027, in Total	221.3
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	592.8	588.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	624.3	611.6	591.5
Accumulated Benefit Obligation	592.8	588.8
Fair Value of Plan Assets	636.7	586.1	570
Underfunded Status, Accumulated Benefit Obligation		(2.7)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	1.6
Components of Net Periodic Benefit Cost
Service Cost	14	12.2	12.9
Interest Cost	24.3	25.3	24.5
Expected Return on Plan Assets	(34.6)	(33.6)	(32.6)
Amortization of Prior Service Cost (Credit)	0.2	0.1	0.2
Amortization of Net Actuarial Loss	9.7	10	12.6
Net Periodic Benefit Cost (Credit)	13.6	14	17.6
Capitalized Portion	(5.5)	(3.3)	(4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	8.1	10.7	13.6
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	10.1
Total Estimated 2018 Amortization	10.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	10.1
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	35.1
2,019	37.2
2,020	37.6
2,021	38.7
2,022	40.4
Years 2023 to 2027, in Total	210.8
Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	483.5	478
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	501.1	492.9	497.5
Accumulated Benefit Obligation	483.5	478
Fair Value of Plan Assets	509.1	473.8	472.1
Underfunded Status, Accumulated Benefit Obligation		(4.2)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	1.2
Components of Net Periodic Benefit Cost
Service Cost	7.5	6.5	6.7
Interest Cost	19.4	20.6	20.3
Expected Return on Plan Assets	(27.9)	(27.6)	(27.5)
Amortization of Prior Service Cost (Credit)	0.1	0.1	0.2
Amortization of Net Actuarial Loss	7.8	8.1	10.5
Net Periodic Benefit Cost (Credit)	6.9	7.7	10.2
Capitalized Portion	(3.3)	(3.4)	(4.8)
Net Periodic Benefit Cost (Credit) Recognized in Expense	3.6	4.3	5.4
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	8.1
Total Estimated 2018 Amortization	8.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	8.1
Pension Plans [Member] | Ohio Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	35.1
2,019	35
2,020	35.1
2,021	34.3
2,022	35
Years 2023 to 2027, in Total	165.6
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	259.6	254.2
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	276.6	266.7	265.4
Accumulated Benefit Obligation	259.6	254.2
Fair Value of Plan Assets	287.8	266	262.1
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	0.2
Components of Net Periodic Benefit Cost
Service Cost	6.4	6.2	6.4
Interest Cost	10.7	11.2	10.9
Expected Return on Plan Assets	(15.6)	(15.5)	(15.1)
Amortization of Prior Service Cost (Credit)	0	0.3	0.2
Amortization of Net Actuarial Loss	4.3	4.4	5.7
Net Periodic Benefit Cost (Credit)	5.8	6.6	8.1
Capitalized Portion	(2.1)	(2.4)	(2.8)
Net Periodic Benefit Cost (Credit) Recognized in Expense	3.7	4.2	5.3
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4.5
Total Estimated 2018 Amortization	4.5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	4.5
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	18.6
2,019	19.5
2,020	19.8
2,021	21.7
2,022	21.1
Years 2023 to 2027, in Total	104.3
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	291.6	281.5
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	314.6	296.6	282.8
Accumulated Benefit Obligation	291.6	281.5
Fair Value of Plan Assets	311.7	287.3	280.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	2.8
Components of Net Periodic Benefit Cost
Service Cost	8.7	8.1	8.3
Interest Cost	12.3	12.4	11.8
Expected Return on Plan Assets	(17)	(16.4)	(16)
Amortization of Prior Service Cost (Credit)	0.1	0.3	0.3
Amortization of Net Actuarial Loss	4.9	4.8	6
Net Periodic Benefit Cost (Credit)	9	9.2	10.4
Capitalized Portion	(2.7)	(2.7)	(3.2)
Net Periodic Benefit Cost (Credit) Recognized in Expense	6.3	6.5	7.2
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	5.1
Total Estimated 2018 Amortization	5.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	5.1
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	20.8
2,019	21.6
2,020	21.8
2,021	23.2
2,022	23.3
Years 2023 to 2027, in Total	121.5
Qualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,951.3	4,846
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,951.3	4,846
Qualified Pension Plans [Member] | AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	421.4	404.7
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	421.4	404.7
Qualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	648	641
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	648	641
Qualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	592.4	588.5
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	592.4	588.5
Qualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	483.4	478
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	483.4	478
Qualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	256.9	252
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	256.9	252
Qualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	289.4	279.8
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	289.4	279.8
Nonqualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	73.9	69.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	78
Accumulated Benefit Obligation	73.9	69.8
Fair Value of Plan Assets	0
Underfunded Status, Accumulated Benefit Obligation	(73.9)
Nonqualified Pension Plans [Member] | AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	3.8	3.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	4	3.8
Accumulated Benefit Obligation	3.8	3.8
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(3.8)	(3.8)
Nonqualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.2	0.3
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	0.4
Accumulated Benefit Obligation	0.2	0.3
Fair Value of Plan Assets	0
Underfunded Status, Accumulated Benefit Obligation	(0.2)
Nonqualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.4	0.3
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	1
Accumulated Benefit Obligation	0.4	0.3
Fair Value of Plan Assets	0
Underfunded Status, Accumulated Benefit Obligation	(0.4)
Nonqualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.1	0
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	0.4
Accumulated Benefit Obligation	0.1	0
Fair Value of Plan Assets	0
Underfunded Status, Accumulated Benefit Obligation	(0.1)
Nonqualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	2.7	2.2
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	2.7	2.3
Accumulated Benefit Obligation	2.7	2.2
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(2.7)	(2.2)
Nonqualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	2.2	1.7
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	2.2	1.7
Accumulated Benefit Obligation	2.2	1.7
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(2.2)	(1.7)
Other Postretirement Benefit Plans [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	1,332	1,447.4	1,450.6
Fair Value of Plan Assets	1,732.5	1,545.9	1,577.4
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	4.2
Components of Net Periodic Benefit Cost
Service Cost	11.2	10.2	12.2
Interest Cost	59.3	60.9	56.8
Expected Return on Plan Assets	(101.3)	(107)	(111)
Amortization of Prior Service Cost (Credit)	(69.1)	(69)	(69.1)
Amortization of Net Actuarial Loss	36.7	31.4	18.8
Net Periodic Benefit Cost (Credit)	(63.2)	(73.5)	(92.3)
Capitalized Portion	25.6	26.9	33.5
Net Periodic Benefit Cost (Credit) Recognized in Expense	(37.6)	(46.6)	(58.8)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	9.8
Prior Service Cost (Credit)	(69.1)
Total Estimated 2018 Amortization	(59.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(59.3)
Other Postretirement Benefit Plans [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	122.8
2,019	123.1
2,020	124
2,021	124.6
2,022	124.6
Years 2023 to 2027, in Total	616.4
Other Postretirement Benefit Plans [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0.3
2,019	0.3
2,020	0.3
2,021	0.3
2,022	0.3
Years 2023 to 2027, in Total	1.7
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	107.1	120.4	122
Fair Value of Plan Assets	147.3	134.1	138.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	0.7	0.8
Interest Cost	4.9	5.1	4.8
Expected Return on Plan Assets	(8.8)	(9.3)	(9.9)
Amortization of Prior Service Cost (Credit)	(5.8)	(6)	(5.9)
Amortization of Net Actuarial Loss	3.2	2.8	1.5
Net Periodic Benefit Cost (Credit)	(5.6)	(6.7)	(8.7)
Capitalized Portion	2.9	3.4	4.1
Net Periodic Benefit Cost (Credit) Recognized in Expense	(2.7)	(3.3)	(4.6)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	0.7
Prior Service Cost (Credit)	(5.8)
Total Estimated 2018 Amortization	(5.1)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(5.1)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	10.2
2,019	10.4
2,020	10.5
2,021	10.7
2,022	10.8
Years 2023 to 2027, in Total	53.7
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Years 2023 to 2027, in Total	0
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	236.5	255.6	262.2
Fair Value of Plan Assets	273.4	246.9	256.7
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	2.5
Components of Net Periodic Benefit Cost
Service Cost	1.1	1	1.1
Interest Cost	10.6	10.8	10.3
Expected Return on Plan Assets	(16.5)	(17.3)	(18.1)
Amortization of Prior Service Cost (Credit)	(10.1)	(10.1)	(10)
Amortization of Net Actuarial Loss	6.3	5.4	3.6
Net Periodic Benefit Cost (Credit)	(8.6)	(10.2)	(13.1)
Capitalized Portion	3.5	3.9	5
Net Periodic Benefit Cost (Credit) Recognized in Expense	(5.1)	(6.3)	(8.1)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	1.9
Prior Service Cost (Credit)	(10.1)
Total Estimated 2018 Amortization	(8.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(8.2)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	23.3
2,019	22.8
2,020	22.8
2,021	22.6
2,022	22.3
Years 2023 to 2027, in Total	106.2
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0.2
2,019	0.2
2,020	0.2
2,021	0.2
2,022	0.2
Years 2023 to 2027, in Total	0.9
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	153.5	167.6	166.3
Fair Value of Plan Assets	211.1	186.6	189
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	0
Components of Net Periodic Benefit Cost
Service Cost	1.6	1.5	1.6
Interest Cost	6.9	7	6.4
Expected Return on Plan Assets	(12.2)	(12.9)	(13.2)
Amortization of Prior Service Cost (Credit)	(9.4)	(9.4)	(9.4)
Amortization of Net Actuarial Loss	4.4	3.7	2
Net Periodic Benefit Cost (Credit)	(8.7)	(10.1)	(12.6)
Capitalized Portion	3.5	2.4	2.9
Net Periodic Benefit Cost (Credit) Recognized in Expense	(5.2)	(7.7)	(9.7)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	1
Prior Service Cost (Credit)	(9.4)
Total Estimated 2018 Amortization	(8.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(8.4)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	14.9
2,019	14.9
2,020	15
2,021	15.2
2,022	15.2
Years 2023 to 2027, in Total	74.8
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Years 2023 to 2027, in Total	0
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	144.3	164	168.6
Fair Value of Plan Assets	198.5	182.6	191.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	0.8	0.9
Interest Cost	6.7	7	6.4
Expected Return on Plan Assets	(11.9)	(13)	(13.4)
Amortization of Prior Service Cost (Credit)	(6.9)	(6.9)	(7)
Amortization of Net Actuarial Loss	4.3	3.8	2.1
Net Periodic Benefit Cost (Credit)	(6.9)	(8.3)	(11)
Capitalized Portion	3.3	3.7	5.2
Net Periodic Benefit Cost (Credit) Recognized in Expense	(3.6)	(4.6)	(5.8)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	1
Prior Service Cost (Credit)	(6.9)
Total Estimated 2018 Amortization	(5.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(5.9)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	14.6
2,019	14.7
2,020	14.6
2,021	14.5
2,022	14.5
Years 2023 to 2027, in Total	69.6
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Years 2023 to 2027, in Total	0
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	69.4	77.6	77.7
Fair Value of Plan Assets	95.5	86.4	88.3
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	0
Components of Net Periodic Benefit Cost
Service Cost	0.7	0.6	0.7
Interest Cost	3.2	3.3	3
Expected Return on Plan Assets	(5.6)	(6.1)	(6.3)
Amortization of Prior Service Cost (Credit)	(4.3)	(4.3)	(4.3)
Amortization of Net Actuarial Loss	2	1.8	1
Net Periodic Benefit Cost (Credit)	(4)	(4.7)	(5.9)
Capitalized Portion	1.4	1.7	2
Net Periodic Benefit Cost (Credit) Recognized in Expense	(2.6)	(3)	(3.9)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	0.5
Prior Service Cost (Credit)	(4.3)
Total Estimated 2018 Amortization	(3.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(3.8)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	6.5
2,019	6.6
2,020	6.8
2,021	6.8
2,022	6.8
Years 2023 to 2027, in Total	34.7
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Years 2023 to 2027, in Total	0
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	80.3	86.9	86.1
Fair Value of Plan Assets	110.4	96.8	97.8
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2018	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	0.8	0.8
Interest Cost	3.6	3.6	3.4
Expected Return on Plan Assets	(6.3)	(6.8)	(6.9)
Amortization of Prior Service Cost (Credit)	(5.2)	(5)	(5.2)
Amortization of Net Actuarial Loss	2.3	1.9	1.1
Net Periodic Benefit Cost (Credit)	(4.7)	(5.5)	(6.8)
Capitalized Portion	1.4	1.6	2.1
Net Periodic Benefit Cost (Credit) Recognized in Expense	(3.3)	$ (3.9)	$ (4.7)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	0.6
Prior Service Cost (Credit)	(5.2)
Total Estimated 2018 Amortization	(4.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(4.6)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,018	7.1
2,019	7.1
2,020	7.4
2,021	7.6
2,022	7.7
Years 2023 to 2027, in Total	40.4
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Years 2023 to 2027, in Total	0
Regulatory Assets [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	75.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	75.9
Regulatory Assets [Member] | Pension Plans [Member] | AEP Texas Inc. [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	6.8
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	6.8
Regulatory Assets [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	10.8
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	10.8
Regulatory Assets [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	9.5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	9.5
Regulatory Assets [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	8.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	8.1
Regulatory Assets [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	4.5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	4.5
Regulatory Assets [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	5.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	5.1
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(42.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(42.9)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(5.1)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(5.1)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(4.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(4.2)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(7.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(7.6)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(5.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(5.9)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(3.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(3.8)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(2.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(2.8)
Deferred Income Taxes [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	2
Deferred Income Taxes [Member] | Pension Plans [Member] | AEP Texas Inc. [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0.1
Deferred Income Taxes [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0.1
Deferred Income Taxes [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(3.5)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(3.5)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(0.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(0.8)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(0.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(0.2)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(0.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(0.4)
Net of Tax AOCI [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	7.6
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	7.6
Net of Tax AOCI [Member] | Pension Plans [Member] | AEP Texas Inc. [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0.3
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0.3
Net of Tax AOCI [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0.5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0.5
Net of Tax AOCI [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(12.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(12.9)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(3.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(3.2)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(0.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	(0.6)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2018 Amortization	(1.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2018	$ (1.4)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended											12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Reportable Segment Information
Vertically Integrated Utilities													$ 9,095.1	$ 9,012.4		$ 9,069.9
Transmission and Distribution Utilities													4,328.9	4,328.3		4,392
Generation and Marketing Revenues													1,771.4	2,858.7		2,866.7
Corporate and Other Revenues													229.5	180.7		124.6
Sales to AEP Affiliates													0	0		0
Total Revenues		$ 3,810.4	$ 4,104.7	$ 3,576.5	$ 3,933.3	$ 3,790.1		$ 4,652.2		$ 3,892.9		$ 4,044.9	15,424.9	16,380.1		16,453.2
Asset Impairments and Other Related Charges													87.1	2,267.8		0
Depreciation and Amortization													1,997.2	1,962.3		2,009.7
Interest and Investment Income													16	16.3		7.9
Carrying Costs Income													18.6	16.2		23.5
Allowance for Equity Funds Used During Construction													93.7	113.2		131.9
Interest Expense													895	877.2		873.9
Income Tax Expense (Credit)													969.7	(73.7)		919.6
Income from Continuing Operations						375.2		(764.2)	[1]	506.4		503.1	1,928.9	620.5		1,768.6
Income (Loss) from Discontinued Operations, Net of Tax						0		0		(2.5)	[2]	0	0	(2.5)		283.7
NET INCOME (LOSS)		401.8	556.7	376.2	594.2	375.2		(764.2)	[1]	503.9		503.1	1,928.9	618		2,052.3
Gross Property Additions													5,698.1	4,889		4,513.3
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		67,428.5				62,036.6							67,428.5	62,036.6
Accumulated Depreciation and Amortization		17,167				16,397.3							17,167	16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		50,261.5				45,639.3	[3]						50,261.5	45,639.3	[3]
Assets Held for Sale						1,951.2								1,951.2
Total Assets		64,729.1				63,467.7							64,729.1	63,467.7		61,683.1
Investments in Equity Method Investees		812.3				809.4							812.3	809.4
Long-term Debt Due Within One Year		1,753.7				2,878							1,753.7	2,878
Long-term Debt - Affiliated		0				0							0	0
Long-term Debt		19,419.6				17,378.4							19,419.6	17,378.4
Total Long-term Debt Outstanding		21,173.3				20,256.4							21,173.3	20,256.4
Disposal Group, Including Discontinued Operation, Liabilities, Current		0				235.9							0	235.9
Vertically Integrated Utilities [Member]
Reportable Segment Information
Vertically Integrated Utilities													9,095.1	9,012.4		9,069.9
Sales to AEP Affiliates													96.9	79.5		102.3
Total Revenues													9,192	9,091.9		9,172.2
Asset Impairments and Other Related Charges													33.6	10.5
Depreciation and Amortization													1,142.5	1,073.8		1,062.6
Interest and Investment Income													6.8	4.8		4.6
Carrying Costs Income													15.2	10.5		11.8
Interest Expense													540	522.1		517.4
Income Tax Expense (Credit)													425.6	397.3		449.3
Income from Continuing Operations													803.3	984		900.2
Income (Loss) from Discontinued Operations, Net of Tax													0	0		0
NET INCOME (LOSS)													803.3	984		900.2
Gross Property Additions													2,343.2	2,237		2,222.3
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		43,294.4				41,552.6							43,294.4	41,552.6
Accumulated Depreciation and Amortization		13,153.4				12,596.7							13,153.4	12,596.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		30,141				28,955.9							30,141	28,955.9
Assets Held for Sale						0								0
Total Assets		37,579.7				37,428.3							37,579.7	37,428.3		35,792.3
Investments in Equity Method Investees		37.1				41.2							37.1	41.2
Long-term Debt Due Within One Year		1,038.1				1,519.9							1,038.1	1,519.9
Long-term Debt - Affiliated		50				20							50	20
Long-term Debt		10,801.4				10,353.3							10,801.4	10,353.3
Total Long-term Debt Outstanding		11,889.5				11,893.2							11,889.5	11,893.2
Disposal Group, Including Discontinued Operation, Liabilities, Current						0								0
Transmission and Distribution Companies [Member]
Reportable Segment Information
Transmission and Distribution Utilities													4,328.9	4,328.3		4,392
Sales to AEP Affiliates													90.4	94.1		164.6
Total Revenues													4,419.3	4,422.4		4,556.6
Asset Impairments and Other Related Charges													0	0
Depreciation and Amortization													667.5	649.9		686.4
Interest and Investment Income													7.7	14.8		6.4
Carrying Costs Income													3.6	20		11.8
Interest Expense													244.1	256.9		276.2
Income Tax Expense (Credit)													127.2	205.1		185.5
Income from Continuing Operations													636.4	482.1		352.4
Income (Loss) from Discontinued Operations, Net of Tax													0	0		0
NET INCOME (LOSS)													636.4	482.1		352.4
Gross Property Additions													1,558.4	1,058.3		1,048.4
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		16,371.2				14,762.2							16,371.2	14,762.2
Accumulated Depreciation and Amortization		3,768.3				3,655							3,768.3	3,655
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		12,602.9				11,107.2							12,602.9	11,107.2
Assets Held for Sale						0								0
Total Assets		16,060.7				14,802.4							16,060.7	14,802.4		14,795
Investments in Equity Method Investees		1.5				1.2							1.5	1.2
Long-term Debt Due Within One Year		663.1				309.4							663.1	309.4
Long-term Debt - Affiliated		0				0							0	0
Long-term Debt		4,705.4				4,672.2							4,705.4	4,672.2
Total Long-term Debt Outstanding		5,368.5				4,981.6							5,368.5	4,981.6
Disposal Group, Including Discontinued Operation, Liabilities, Current						0								0
AEP Transmission Holdco
Reportable Segment Information
Transmission Revenue													178.4	145.9		100.6
Sales to AEP Affiliates													588.3	366.9		228.6
Total Revenues													766.7	512.8		329.2
Asset Impairments and Other Related Charges													0	0
Depreciation and Amortization													102.2	67.1		43
Interest and Investment Income													1.2	0.4		0.2
Carrying Costs Income													(0.2)	(0.3)		(0.2)
Interest Expense													72.8	50.3		37.2
Income Tax Expense (Credit)													189.8	134.1		91.3
Income from Continuing Operations													355.6	269.3		192.7
Income (Loss) from Discontinued Operations, Net of Tax													0	0		0
NET INCOME (LOSS)													355.6	269.3		192.7
Gross Property Additions													1,542.8	1,265.8		1,121.3
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		7,110.2				5,354							7,110.2	5,354
Accumulated Depreciation and Amortization		176.6				101.4							176.6	101.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,933.6				5,252.6							6,933.6	5,252.6
Assets Held for Sale						0								0
Total Assets		8,141.8				6,384.8							8,141.8	6,384.8		5,012.1
Investments in Equity Method Investees		742.9				742							742.9	742
Long-term Debt Due Within One Year		50				0							50	0
Long-term Debt - Affiliated		0				0							0	0
Long-term Debt		2,631.3				2,055.7							2,631.3	2,055.7
Total Long-term Debt Outstanding		2,681.3				2,055.7							2,681.3	2,055.7
Disposal Group, Including Discontinued Operation, Liabilities, Current						0								0
Generation and Marketing [Member]
Reportable Segment Information
Generation and Marketing Revenues													1,771.4	2,858.7		2,866.7
Sales to AEP Affiliates													103.7	127.3		546
Total Revenues													1,875.1	2,986		3,412.7
Asset Impairments and Other Related Charges													53.5	2,257.3
Depreciation and Amortization													24.2	154.6		201.4
Interest and Investment Income													10.3	1.4		2.8
Carrying Costs Income													0	0		0
Interest Expense													18.5	35.8		40
Income Tax Expense (Credit)													189.7	(666.5)		194.6
Income from Continuing Operations													166	(1,198)		366
Income (Loss) from Discontinued Operations, Net of Tax													0	0		0
NET INCOME (LOSS)													166	(1,198)		366
Gross Property Additions													328.5	336.2		134.3
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		644.6				364.7							644.6	364.7
Accumulated Depreciation and Amortization		75				42.2							75	42.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		569.6				322.5							569.6	322.5
Assets Held for Sale						1,951.2								1,951.2
Total Assets		2,009.8				3,386.1							2,009.8	3,386.1		5,414.5
Investments in Equity Method Investees		16.6				0.1							16.6	0.1
Long-term Debt Due Within One Year		0				500.1							0	500.1
Long-term Debt - Affiliated		32.2				32.2							32.2	32.2
Long-term Debt		(0.3)				0							(0.3)	0
Total Long-term Debt Outstanding		31.9				532.3							31.9	532.3
Disposal Group, Including Discontinued Operation, Liabilities, Current						235.9								235.9
All Other [Member]
Reportable Segment Information
Corporate and Other Revenues													51.1	34.8		24
Sales to AEP Affiliates													69.7	70.3		75
Total Revenues	[4]												120.8	105.1		99
Asset Impairments and Other Related Charges	[4]												0	0
Depreciation and Amortization	[4]												0.3	0.2		0.8
Interest and Investment Income	[4]												23.3	11.8		9.2
Carrying Costs Income	[4]												0	0		0
Interest Expense	[4]												63.9	40.5		30.3
Income Tax Expense (Credit)	[4]												37.4	(143.7)		(1.1)
Income from Continuing Operations	[4]												(32.4)	83.1		(42.7)
Income (Loss) from Discontinued Operations, Net of Tax	[4]												0	(2.5)		283.7
NET INCOME (LOSS)	[4]												(32.4)	80.6		241
Gross Property Additions	[4]												15.6	9.8		4.8
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)	[4]	374.5				356.6							374.5	356.6
Accumulated Depreciation and Amortization	[4]	180.6				186							180.6	186
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[4]	193.9				170.6							193.9	170.6
Assets Held for Sale	[4]					0								0
Total Assets	[4],[5]	3,959.1				3,883.4							3,959.1	3,883.4		3,628.5
Investments in Equity Method Investees	[4]	14.2				24.9							14.2	24.9
Long-term Debt Due Within One Year	[4]	2.5				548.6							2.5	548.6
Long-term Debt - Affiliated	[4]	0				0							0	0
Long-term Debt	[4]	1,281.8				297.2							1,281.8	297.2
Total Long-term Debt Outstanding	[4]	1,284.3				845.8							1,284.3	845.8
Disposal Group, Including Discontinued Operation, Liabilities, Current						0								0
Reconciling Adjustments [Member]
Reportable Segment Information
Corporate and Other Revenues													0	0		0
Sales to AEP Affiliates													(949)	(738.1)		(1,116.5)
Total Revenues													(949)	(738.1)		(1,116.5)
Asset Impairments and Other Related Charges													0	0
Depreciation and Amortization	[6]												60.5	16.7		15.5
Interest and Investment Income													(33.3)	(16.9)		(15.3)
Carrying Costs Income													0	(14)		0.1
Interest Expense	[6]												(44.3)	(28.4)		(27.2)
Income Tax Expense (Credit)													0	0		0
Income from Continuing Operations													0	0		0
Income (Loss) from Discontinued Operations, Net of Tax													0	0		0
NET INCOME (LOSS)													0	0		0
Gross Property Additions													(90.4)	(18.1)		(17.8)
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)	[6]	(366.4)				(353.5)							(366.4)	(353.5)
Accumulated Depreciation and Amortization	[6]	(186.9)				(184)							(186.9)	(184)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[6]	(179.5)				(169.5)							(179.5)	(169.5)
Assets Held for Sale						0								0
Total Assets	[6],[7]	(3,022)				(2,417.3)							(3,022)	(2,417.3)		(2,959.3)
Investments in Equity Method Investees		0				0							0	0
Long-term Debt Due Within One Year		0				0							0	0
Long-term Debt - Affiliated		(82.2)				(52.2)							(82.2)	(52.2)
Long-term Debt		0				0							0	0
Total Long-term Debt Outstanding		(82.2)				(52.2)							(82.2)	(52.2)
Disposal Group, Including Discontinued Operation, Liabilities, Current						0								0
AEP Transmission Co [Member]
Reportable Segment Information
Transmission Revenue													141.9	110.4		84.3
Corporate and Other Revenues													0.8	0.1		0.3
Sales to AEP Affiliates													580.5	367.5		225.6
Total Revenues		173.8	167.3	229.4	152.7	120		125.3		153.1		79.6	723.2	478		310.2
Depreciation and Amortization													97.1	65.9		42.4
Interest Income													1.2	0.4		0.1
Allowance for Equity Funds Used During Construction													52.3	52.3		53
Interest Expense													68	46		34.6
Income Tax Expense (Credit)													147.2	94.1		60
Income from Continuing Operations						0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax						0		0		0		0
NET INCOME (LOSS)		61.8	$ 59.9	$ 107.4	$ 57	39.7		$ 52.4		$ 74.8		$ 25.8	286.1	192.7		132.9
Gross Property Additions													1,522.5	1,166		1,008.9
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		6,780.2				5,054.2							6,780.2	5,054.2
Accumulated Depreciation and Amortization		170.4				99.6							170.4	99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,609.8				4,954.6							6,609.8	4,954.6
Notes Receivable, Related Parties		0				0							0	0
Total Assets		7,068.1				5,349.8							7,068.1	5,349.8		4,156.5
Long-term Debt Due Within One Year		50				0							50	0
Long-term Debt		2,500.4				1,932							2,500.4	1,932
Total Long-term Debt Outstanding		2,550.4				1,932							2,550.4	1,932
AEP Transmission Co [Member] | State Transcos [Member]
Reportable Segment Information
Transmission Revenue													141.9	110.4		84.3
Corporate and Other Revenues													0.8	0.1		0.3
Sales to AEP Affiliates													580.5	367.5		225.6
Total Revenues													723.2	478		310.2
Depreciation and Amortization													97.1	65.9		42.4
Interest Income													0.7	0.1		0.1
Allowance for Equity Funds Used During Construction													52.3	52.3		53
Interest Expense													68	45.6		34.4
Income Tax Expense (Credit)													147	94.4		60.1
NET INCOME (LOSS)													285.8	193.3		133.2
Gross Property Additions													1,522.5	1,166		1,008.9
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		6,780.2				5,054.2							6,780.2	5,054.2
Accumulated Depreciation and Amortization		170.4				99.6							170.4	99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,609.8				4,954.6							6,609.8	4,954.6
Notes Receivable, Related Parties		0				0							0	0
Total Assets		7,072.9				5,337.5							7,072.9	5,337.5		4,143.6
Total Long-term Debt Outstanding		2,575				1,932							2,575	1,932
AEP Transmission Co [Member] | AEPTCo Parent [Member]
Reportable Segment Information
Transmission Revenue													0	0		0
Corporate and Other Revenues													0	0		0
Sales to AEP Affiliates													0	0		0
Total Revenues													0	0		0
Depreciation and Amortization													0	0		0
Interest Income													82.9	57.8		49.6
Allowance for Equity Funds Used During Construction													0	0		0
Interest Expense													82.4	57.9		49.8
Income Tax Expense (Credit)													0.2	(0.3)		(0.1)
NET INCOME (LOSS)	[8]												0.3	(0.6)		(0.3)
Gross Property Additions													0	0		0
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		0				0							0	0
Accumulated Depreciation and Amortization		0				0							0	0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0				0							0	0
Notes Receivable, Related Parties		2,550.4				1,950							2,550.4	1,950
Total Assets	[9]	2,590.1				1,987.7							2,590.1	1,987.7		1,588.4
Total Long-term Debt Outstanding		2,550.4				1,950							2,550.4	1,950
AEP Transmission Co [Member] | Reconciling Adjustments [Member]
Reportable Segment Information
Transmission Revenue													0	0		0
Corporate and Other Revenues													0	0		0
Sales to AEP Affiliates													0	0		0
Total Revenues													0	0		0
Depreciation and Amortization													0	0		0
Interest Income	[10]												(82.4)	(57.5)		(49.6)
Allowance for Equity Funds Used During Construction													0	0		0
Interest Expense	[10]												(82.4)	(57.5)		(49.6)
Income Tax Expense (Credit)													0	0		0
NET INCOME (LOSS)													0	0		0
Gross Property Additions													0	0		0
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		0				0							0	0
Accumulated Depreciation and Amortization		0				0							0	0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0				0							0	0
Notes Receivable, Related Parties	[11]	(2,550.4)				(1,950)							(2,550.4)	(1,950)
Total Assets	[12]	(2,594.9)				(1,975.4)							(2,594.9)	(1,975.4)		$ (1,575.5)
Total Long-term Debt Outstanding	[11]	$ (2,575)				$ (1,950)							$ (2,575)	$ (1,950)
[1]	Includes impairments for certain merchant generation assets (see Note 7).
[2]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[3]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[4]	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs.
[5]	Includes the elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
[6]	Includes eliminations due to an intercompany capital lease.
[7]	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable
[8]	Includes the elimination of AEPTCo Parent’s equity earnings in State Transcos.
[9]	Includes the elimination of AEPTCo Parent’s investments in State Transcos.
[10]	Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
[11]	Elimination of intercompany debt.
[12]	Primarily relates to the elimination of 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		12 Months Ended
		Dec. 31, 2017USD ($)MWhMMBTUTgal		Dec. 31, 2016USD ($)MWhMMBTUTgal		Dec. 31, 2015USD ($)
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 9,400,000		$ 7,900,000
Cash Collateral Paid Netted Against Risk Management Liabilities		9,000,000		7,600,000
Fair Value of Derivative Instruments
Current Risk Management Assets		126,200,000		94,500,000
Long-term Risk Management Assets		282,100,000		289,100,000
Total Assets		408,300,000		383,600,000
Current Risk Management Liabilities		61,600,000		53,400,000
Long-term Risk Management Liabilities		322,000,000		316,200,000
Total Liabilities		383,600,000		369,600,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		136,000,000		28,400,000		$ 86,400,000
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		243,600,000		259,600,000
Amount of Cash Collateral Posted		1,300,000		400,000
Additional Settlement Liability if Cross Default Provision is Triggered		$ 223,100,000		235,800,000
Derivatives and Hedging (Textuals) [Abstract]
Maximum Length of Time Hedged in Price Risk Cash Flow Hedge		120 months
AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		$ 500,000		200,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		400,000		400,000		(1,100,000)
Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		24,900,000		2,600,000
Long-term Risk Management Assets		1,100,000		0
Current Risk Management Liabilities		1,300,000		300,000
Long-term Risk Management Liabilities		200,000		900,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		43,200,000		56,500,000		36,500,000
Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		7,600,000		3,500,000
Long-term Risk Management Assets		700,000		0
Current Risk Management Liabilities		3,500,000		300,000
Long-term Risk Management Liabilities		100,000		800,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		14,600,000		27,000,000		15,900,000
Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		600,000		200,000
Current Risk Management Liabilities		6,400,000		5,900,000
Long-term Risk Management Liabilities		126,000,000		113,100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(21,800,000)		(143,500,000)		(30,100,000)
Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		6,400,000		800,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		25,000,000		6,600,000		4,200,000
Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		6,400,000		900,000
Current Risk Management Liabilities		200,000		300,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		24,900,000		20,400,000		9,900,000
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[1]	383,800,000	[2]	372,400,000	[3]
Total Liabilities	[1]	309,500,000	[2]	321,500,000	[3]
Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Total Assets	[1]	500,000		200,000
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	26,000,000		2,600,000
Total Liabilities	[1],[4]	1,500,000		1,200,000
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	8,300,000		3,500,000
Total Liabilities	[1],[4]	3,600,000		1,100,000
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	600,000		200,000
Total Liabilities	[1],[4]	132,400,000		119,000,000
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	6,400,000		800,000
Total Liabilities	[1],[4]	0
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	6,400,000		900,000
Total Liabilities	[1],[4]	200,000		300,000
Commodity [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[5]	22,000,000		11,200,000
Hedging Liabilities	[5]	65,500,000		46,700,000
AOCI Gain (Loss) Net of Tax		(28,400,000)		(23,100,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		5,500,000		4,300,000
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50,000,000
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	389,000,000		264,400,000
Long-term Risk Management Assets	[6]	300,900,000		315,000,000
Total Assets	[6]	689,900,000		579,400,000
Current Risk Management Liabilities	[6]	334,600,000		227,200,000
Long-term Risk Management Liabilities	[6]	280,600,000		301,000,000
Total Liabilities	[6]	615,200,000		528,200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	74,700,000		51,200,000
Commodity [Member] | Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	500,000		400,000
Long-term Risk Management Assets	[6]	0		0
Total Assets	[6]	500,000		400,000
Current Risk Management Liabilities	[6]	0		0
Long-term Risk Management Liabilities	[6]	0		0
Total Liabilities	[6]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	500,000		400,000
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	75,600,000		22,700,000
Long-term Risk Management Assets	[6]	2,400,000		1,900,000
Total Assets	[6]	78,000,000		24,600,000
Current Risk Management Liabilities	[6]	50,600,000		20,600,000
Long-term Risk Management Liabilities	[6]	1,400,000		2,800,000
Total Liabilities	[6]	52,000,000		23,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	26,000,000		1,200,000
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	47,200,000		14,900,000
Long-term Risk Management Assets	[6]	1,600,000		1,100,000
Total Assets	[6]	48,800,000		16,000,000
Current Risk Management Liabilities	[6]	48,500,000		11,800,000
Long-term Risk Management Liabilities	[6]	900,000		1,900,000
Total Liabilities	[6]	49,400,000		13,700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	(600,000)		2,300,000
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	600,000		400,000
Long-term Risk Management Assets	[6]	0		0
Total Assets	[6]	600,000		400,000
Current Risk Management Liabilities	[6]	6,400,000		5,900,000
Long-term Risk Management Liabilities	[6]	126,000,000		113,100,000
Total Liabilities	[6]	132,400,000		119,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	(131,800,000)		(118,600,000)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	6,600,000		900,000
Long-term Risk Management Assets	[6]	0		0
Total Assets	[6]	6,600,000		900,000
Current Risk Management Liabilities	[6]	200,000		0
Long-term Risk Management Liabilities	[6]	0		0
Total Liabilities	[6]	200,000		0
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	6,400,000		900,000
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	7,000,000		1,100,000
Long-term Risk Management Assets	[6]	0		0
Total Assets	[6]	7,000,000		1,100,000
Current Risk Management Liabilities	[6]	800,000		400,000
Long-term Risk Management Liabilities	[6]	0		0
Total Liabilities	[6]	800,000		400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	6,200,000		700,000
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	17,500,000		13,200,000
Long-term Risk Management Assets	[6]	6,300,000		7,700,000
Total Assets	[6]	23,800,000		20,900,000
Current Risk Management Liabilities	[6]	9,000,000		6,300,000
Long-term Risk Management Liabilities	[6]	58,300,000		50,100,000
Total Liabilities	[6]	67,300,000		56,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	(43,500,000)		(35,500,000)
Interest Rate and Foreign Currency [Member]
Commodity
Derivative, Notional Amount		500,000,000		500,000,000
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[5]	0		0
Hedging Liabilities	[5]	0		0
AOCI Gain (Loss) Net of Tax		(13,000,000)		(15,700,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(800,000)		(1,000,000)
Interest Rate and Foreign Currency [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(4,500,000)		(5,400,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(900,000)		(900,000)
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		2,200,000		2,900,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		700,000		700,000
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(10,700,000)		(12,000,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,300,000)		(1,300,000)
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		1,900,000		3,000,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		1,100,000		1,100,000
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		2,600,000		3,400,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		800,000		800,000
Interest Rate and Foreign Currency [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(6,000,000)		(7,400,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,400,000)		(1,400,000)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	2,500,000		0
Long-term Risk Management Assets	[6]	0		0
Total Assets	[6]	2,500,000		0
Current Risk Management Liabilities	[6]	0		0
Long-term Risk Management Liabilities	[6]	8,600,000		1,400,000
Total Liabilities	[6]	8,600,000		1,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	(6,100,000)		(1,400,000)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		409,000,000		277,600,000
Long-term Risk Management Assets		307,200,000		322,700,000
Total Assets		716,200,000		600,300,000
Current Risk Management Liabilities		343,600,000		233,500,000
Long-term Risk Management Liabilities		347,500,000		352,500,000
Total Liabilities		691,100,000		586,000,000
Total MTM Derivative Contract Net Assets (Liabilities)		25,100,000		14,300,000
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	(282,800,000)		(183,100,000)
Long-term Risk Management Assets	[7]	(25,100,000)		(33,600,000)
Total Assets	[7]	(307,900,000)		(216,700,000)
Current Risk Management Liabilities	[7]	(282,000,000)		(180,100,000)
Long-term Risk Management Liabilities	[7]	(25,500,000)		(36,300,000)
Total Liabilities	[7]	(307,500,000)		(216,400,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(400,000)		(300,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0		(200,000)
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0		(200,000)
Current Risk Management Liabilities	[7]	0		0
Long-term Risk Management Liabilities	[7]	0		0
Total Liabilities	[7]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	0		(200,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	(50,700,000)		(20,100,000)
Long-term Risk Management Assets	[7]	(1,300,000)		(1,900,000)
Total Assets	[7]	(52,000,000)		(22,000,000)
Current Risk Management Liabilities	[7]	(49,300,000)		(20,300,000)
Long-term Risk Management Liabilities	[7]	(1,200,000)		(1,900,000)
Total Liabilities	[7]	(50,500,000)		(22,200,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(1,500,000)		200,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	(39,600,000)		(11,400,000)
Long-term Risk Management Assets	[7]	(900,000)		(1,100,000)
Total Assets	[7]	(40,500,000)		(12,500,000)
Current Risk Management Liabilities	[7]	(45,000,000)		(11,500,000)
Long-term Risk Management Liabilities	[7]	(800,000)		(1,100,000)
Total Liabilities	[7]	(45,800,000)		(12,600,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	5,300,000		100,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0		(200,000)
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0		(200,000)
Current Risk Management Liabilities	[7]	0		0
Long-term Risk Management Liabilities	[7]	0		0
Total Liabilities	[7]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	0		(200,000)
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	[7]	(200,000)		(100,000)
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	(200,000)		(100,000)
Current Risk Management Liabilities	[7]	(200,000)		0
Long-term Risk Management Liabilities	[7]	0		0
Total Liabilities	[7]	(200,000)		0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	0		(100,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	(600,000)		(200,000)
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	(600,000)		(200,000)
Current Risk Management Liabilities	[7]	(600,000)		(100,000)
Long-term Risk Management Liabilities	[7]	0		0
Total Liabilities	[7]	(600,000)		(100,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	0		(100,000)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	126,200,000		94,500,000
Long-term Risk Management Assets	[8]	282,100,000		289,100,000
Total Assets	[8]	408,300,000		383,600,000
Current Risk Management Liabilities	[8]	61,600,000		53,400,000
Long-term Risk Management Liabilities	[8]	322,000,000		316,200,000
Total Liabilities	[8]	383,600,000		369,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	24,700,000		14,000,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	500,000		200,000
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	500,000		200,000
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	500,000		200,000
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	[8]	24,900,000		2,600,000
Long-term Risk Management Assets	[8]	1,100,000		0
Total Assets	[8]	26,000,000		2,600,000
Current Risk Management Liabilities	[8]	1,300,000		300,000
Long-term Risk Management Liabilities	[8]	200,000		900,000
Total Liabilities	[8]	1,500,000		1,200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	24,500,000		1,400,000
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	[8]	7,600,000		3,500,000
Long-term Risk Management Assets	[8]	700,000		0
Total Assets	[8]	8,300,000		3,500,000
Current Risk Management Liabilities	[8]	3,500,000		300,000
Long-term Risk Management Liabilities	[8]	100,000		800,000
Total Liabilities	[8]	3,600,000		1,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	4,700,000		2,400,000
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	[8]	600,000		200,000
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	600,000		200,000
Current Risk Management Liabilities	[8]	6,400,000		5,900,000
Long-term Risk Management Liabilities	[8]	126,000,000		113,100,000
Total Liabilities	[8]	132,400,000		119,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(131,800,000)		(118,800,000)
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	[8]	6,400,000		800,000
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	6,400,000		800,000
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	6,400,000		800,000
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	[8]	6,400,000		900,000
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	6,400,000		900,000
Current Risk Management Liabilities	[8]	200,000		300,000
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	200,000		300,000
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	$ 6,200,000		$ 600,000
Power [Member]
Commodity
Derivative, Energy Notional Amount | MWh		358.7		348
Power [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Energy Notional Amount | MWh		0		0
Power [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		57.4		51.9
Power [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		38.5		19.9
Power [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		10.4		11.2
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MWh		10.3		11.9
Power [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		22.7		14.2
Coal [Member]
Commodity
Derivative, Mass Notional Amount | T		2		1.5
Coal [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		2		0.5
Coal [Member] | Ohio Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		1
Natural Gas [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		53.7		32.8
Natural Gas [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		1.1		0
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0.7		0
Natural Gas [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		18.3		0
Heating Oil and Gasoline [Member]
Commodity
Derivative, Volume Notional Amount | gal		6.9		7.4
Heating Oil and Gasoline [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.4		1.5
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.3		1.4
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.7		0.7
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.6		1.6
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.7		0.8
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.8		0.9
Interest Rate Contract [Member]
Commodity
Derivative, Notional Amount		$ 50,700,000		$ 75,200,000
Interest Rate Contract [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0		100,000
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0		100,000
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6,100,000		4,000,000		6,700,000
Vertically Integrated Utilities Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
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
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
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
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
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
Transmission and Distribution Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				100,000		(4,300,000)
Transmission and Distribution Utilities Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0		0
Transmission and Distribution 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
Transmission and Distribution 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
Transmission and Distribution 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
Transmission and Distribution 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
Transmission and Distribution 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
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		42,800,000		59,400,000		54,900,000
Generation and Marketing Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
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
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
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
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
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
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
Electric Generation, Transmission and Distribution Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		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		600,000		(600,000)		1,100,000
Electric Generation, Transmission and Distribution Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		5,300,000		4,100,000		3,300,000
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		100,000		(4,300,000)
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		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		100,000		0		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] | AEP Texas Inc. [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				2,100,000		2,400,000
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				5,800,000		8,200,000
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		5,600,000		6,600,000		6,400,000
Purchased Electricity for Resale [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
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		2,000,000		3,500,000		2,000,000
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		600,000		300,000		400,000
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
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
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
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		800,000		(1,600,000)		(3,300,000)
Other Operation Expense [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		(400,000)		(800,000)
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		100,000		(100,000)		(400,000)
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		100,000		(100,000)		(400,000)
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		100,000		(300,000)		(600,000)
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		100,000		(100,000)		(400,000)
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		100,000		(300,000)		(500,000)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		700,000		(1,800,000)		(3,300,000)
Maintenance Expense [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		200,000		(400,000)		(700,000)
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		100,000		(400,000)		(700,000)
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		100,000		(100,000)		(400,000)
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		100,000		(400,000)		(500,000)
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		100,000		(200,000)		(400,000)
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		100,000		(200,000)		(400,000)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[9]	(29,400,000)		(117,400,000)		(900,000)
Regulatory Assets [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[9]	0		800,000		400,000
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	[9]	0		600,000		3,400,000
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	[9]	(7,400,000)		3,100,000		(2,700,000)
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	[9]	(22,000,000)		(127,700,000)		0
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	[9]	0		400,000		600,000
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	[9]	300,000		5,200,000		(4,300,000)
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[9]	109,400,000		79,100,000		30,200,000
Regulatory Liabilities [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[9]	100,000		400,000		0
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	[9]	40,400,000		51,400,000		28,700,000
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	[9]	15,900,000		13,900,000		7,500,000
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	[9]	0		(15,200,000)		(24,700,000)
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	[9]	24,800,000		6,500,000		4,400,000
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	[9]	$ 24,300,000		$ 15,700,000		$ 15,100,000
[1]	Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
[2]	The December 31, 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 periods 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.
[3]	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.
[4]	Substantially comprised of power contracts.
[5]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
[6]	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.”
[7]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[9]	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		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 21,173.3	$ 20,256.4
Long-term Debt, Fair Value		23,649.6
Other Temporary Investments
Cost		341.4	318.8
Gross Unrealized Gains		19.7	13.9
Gross Unrealized Losses		(1.4)	(1)
Fair Value		359.7	331.7
Debt and Equity Securities Within Other Temporary Investments
Proceeds From Investment Sales		0	0		$ 0
Purchases of Investments		14.2	2.3		10.7
Gross Realized Gains on Investment Sales		0	0		0
Gross Realized Losses on Investment Sales		0	0		0
Nuclear Trust Fund Investments
Fair Value		2,527.6	2,256.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,527.6	2,256.2
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		23,649.6
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		902.5	707.7
Other-Than-Temporary Impairments		(80.5)	(87.2)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,256.3	2,957.7		2,218.4
Purchases of Investments		2,300.5	3,000		2,272
Gross Realized Gains on Investment Sales		200.7	46.1		69.1
Gross Realized Losses on Investment Sales		146	24.4		53
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		387.3
After 1 year through 5 years		287.4
After 5 years through 10 years		204.4
After 10 years		169.6
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000	938
Adjusted Cost of Domestic Equity Securities		594	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		21,173.3	20,391.2	[1],[2]
Long-term Debt, Fair Value	[1]		22,211.9
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value	[1]		22,211.9
AEP Texas Inc. [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,649.3	3,217.7
Long-term Debt, Fair Value		3,964.8	3,463.2
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		3,964.8	3,463.2
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,550.4	1,932
Long-term Debt, Fair Value		2,782.9	1,984.3
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		2,782.9	1,984.3
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,980.1	4,033.9
Long-term Debt, Fair Value		4,782.6	4,613.2
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		4,782.6	4,613.2
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,745.1	2,471.4
Long-term Debt, Fair Value		3,014.7	2,661.6
Nuclear Trust Fund Investments
Fair Value		2,527.6	2,256.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,527.6	2,256.2
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		3,014.7	2,661.6
Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		902.5	707.7
Other-Than-Temporary Impairments		(80.5)	(87.2)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,256.3	2,957.7		2,218.4
Purchases of Investments		2,300.5	3,000		2,272
Gross Realized Gains on Investment Sales		200.7	46.1		69.1
Gross Realized Losses on Investment Sales		146	24.4		$ 53
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		387.3
After 1 year through 5 years		287.4
After 5 years through 10 years		204.4
After 10 years		169.6
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000	938
Adjusted Cost of Domestic Equity Securities		594	592
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,719.3	1,763.9
Long-term Debt, Fair Value		2,064.3	2,092.5
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		2,064.3	2,092.5
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,286.5	1,286
Long-term Debt, Fair Value		1,457.1	1,419
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		1,457.1	1,419
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,441.9	2,679.1
Long-term Debt, Fair Value		2,645.9	2,814.3
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		2,645.9	2,814.3
Cash [Member]
Other Temporary Investments
Cost	[3]	220.1	211.7
Gross Unrealized Gains	[3]	0	0
Gross Unrealized Losses	[3]	0	0
Fair Value	[3],[4]	220.1	211.7
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,048.7	967.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,048.7	967.4
Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		34.3	29.8
Other-Than-Temporary Impairments		(5)	(7.6)
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		1,048.7	967.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,048.7	967.4
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		34.3	29.8
Other-Than-Temporary Impairments		(5)	(7.6)
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[5]	104.3	92.7
Gross Unrealized Gains	[5]	0	0
Gross Unrealized Losses	[5]	(1.4)	(1)
Fair Value	[5]	102.9	91.7
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	1,461.7	1,270.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[6]	1,461.7	1,270.1
Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		868.2	677.9
Other-Than-Temporary Impairments		(75.5)	(79.6)
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	1,461.7	1,270.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[6]	1,461.7	1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		868.2	677.9
Other-Than-Temporary Impairments		(75.5)	(79.6)
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		17	14.4
Gross Unrealized Gains		19.7	13.9
Gross Unrealized Losses		0	0
Fair Value		36.7	28.3
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	17.2	18.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	17.2	18.7
Cash and Cash Equivalents [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0	0
Other-Than-Temporary Impairments		0	0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	17.2	18.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	17.2	18.7
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0	0
Other-Than-Temporary Impairments		0	0
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		981.2	785.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		981.2	785.4
US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		29.7	27.1
Other-Than-Temporary Impairments		(3.6)	(5.5)
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		981.2	785.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		981.2	785.4
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		29.7	27.1
Other-Than-Temporary Impairments		(3.6)	(5.5)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		58.7	60.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value		58.7	60.9
Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		3.8	2.3
Other-Than-Temporary Impairments		(1.2)	(1.4)
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		58.7	60.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value		58.7	60.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		3.8	2.3
Other-Than-Temporary Impairments		(1.2)	(1.4)
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		8.8	121.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		8.8	121.1
State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.8	0.4
Other-Than-Temporary Impairments		(0.2)	(0.7)
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		8.8	121.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		8.8	121.1
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.8	0.4
Other-Than-Temporary Impairments		$ (0.2)	$ (0.7)
[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 7 for additional information.
[2]	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 7 for additional information.
[3]	Primarily represents amounts held for the repayment of debt.
[4]	Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[5]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[6]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[7]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Fair Value Financial Assets Lia

Fair Value Financial Assets Liabilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2017USD ($)$ / MWh		Dec. 31, 2016USD ($)$ / MWh		Dec. 31, 2015USD ($)
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			$ 210.5
Other Temporary Investments		$ 359.7		331.7
Risk Management Assets
Risk Management Assets		408.3		383.6
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,527.6		2,256.2
Total Assets		3,295.6		3,182
Liabilities, Fair Value Disclosure
Risk Management Liabilities		383.6		369.6
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		2.5		146.9		$ 150.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	37.3		42.8		13.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	33.6		26.1		53.7
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		(18.8)		(23)		(4.9)
Settlements		(50.6)		(71.4)		(63)
Transfers into Level 3	[4],[5]	16.2		13.3		28.7
Transfers out of Level 3	[5]	(10.1)		(2.6)		(18.9)
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	30.2		(129.6)		(13)
Ending Balance		$ 40.3		$ 2.5		146.9
Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]	0.08%		0.35%
High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]	4.56%		8.24%
Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]	1.80%		3.91%
Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			$ 201.8
Other Temporary Investments		$ 36.9		32.8
Risk Management Assets
Risk Management Assets		(285.4)		(213)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9.7		11.4
Total Assets		(238.8)		33
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(285)		(212.7)
Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			8.7
Other Temporary Investments		322.8		293.8
Risk Management Assets
Risk Management Assets		3.9		6
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,469.2		1,277.4
Total Assets		1,795.9		1,585.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5.1		8.2
Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Other Temporary Investments		0		5.1
Risk Management Assets
Risk Management Assets		411		396.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,048.7		967.4
Total Assets		1,459.7		1,369.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities		425		382.7
Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Other Temporary Investments		0		0
Risk Management Assets
Risk Management Assets		278.8		193.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		278.8		193.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		238.5		191.4
2017 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				20
2017 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				17
2018 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(1)
2018 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(3)
2018 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		59
2018 - 2020 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				(2)
2018 - 2020 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				4
2018 - 2020 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				28
2019 - 2021 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		33
2021 - 2022 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				3
2021 - 2022 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				11
2022 - 2023 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		2
2022 - 2023 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		14
2023 - 2032 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				1
2023 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				(31)
2024 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(29)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8]	383.8	[9]	372.4	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	309.5	[9]	321.5	[10]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8]	(285.4)	[9]	(205.7)	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	(285)	[9]	(205.4)	[10]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8]	3.9	[9]	6	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	5.1	[9]	8.2	[10]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8]	391.2	[9]	379.9	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	392.5	[9]	352	[10]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8]	274.1	[9]	192.2	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	196.9	[9]	166.7	[10]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		225.1		183.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 233.7		$ 187.1
Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.05)		6.51
Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	263		86.59
Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	36.32		39.40
Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2
Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[12]	2.37
Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[12]	2.96
Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[12]	2.62
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 53.7		$ 10.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 4.6		$ 4.3
FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(55.62)		(7.99)
FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	54.88		8.91
FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	0.41		0.86
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[8]	$ 22		$ 11.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	65.5		46.7
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8]	0		(7.3)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	0		(7.3)
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	0		0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8]	17.3		16.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	23.9		29.3
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8]	4.7		1.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	41.6		24.7
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets		2.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		8.6		1.4
Fair Value Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0		0
Fair Value Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0		0
Fair Value Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		2.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		8.6		1.4
Fair Value Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0		0
AEP Texas Inc. [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		155.2		146.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		155.7		146.5
AEP Texas Inc. [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		(0.2)
AEP Texas Inc. [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		155.2		146.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		155.2		146.3
AEP Texas Inc. [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.5		0.4
AEP Texas Inc. [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8]	0.5		0.2
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8]	0		(0.2)
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8]	0		0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8]	0.5		0.4
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8]	0		0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		16.3		15.9	[1]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		42.3		18.5
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance	[13]	1.4		11.7		15.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	17.2		25.6	[13]	2.1	[13]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0	[13]	0	[13]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	[13]	0	[13]
Settlements		(18.9)		(37.5)	[13]	(17.2)	[13]
Transfers into Level 3	[4],[5]	0		0	[13]	0	[13]
Transfers out of Level 3	[5]	0		0.1	[13]	1.2	[13]
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	25		1.5	[13]	9.8	[13]
Ending Balance		24.7		1.4	[13]	11.7	[13]
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		0		0.1	[1]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(51.6)		(21.7)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		16.3		15.8	[1]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16.3		15.8
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		0		0	[1]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		52.5		20.5
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents		0		0	[1]
Risk Management Assets
Risk Management Assets		25.1		3.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		25.1		3.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.4		2.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	26		2.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	1.5		1.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(51.6)		(21.8)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(50.1)		(22)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	52.5		20.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	51.2		20.7
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	25.1		3.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.4		2.5
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.8		0.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.4		$ 0.4
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	20.52		19.68
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	195		48.55
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	33.80		36.34
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 24.3		$ 3.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0		$ 2.1
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.36)		(0.23)
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	7.15		8.91
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	1.62		2.37
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,527.6		$ 2,256.2
Total Assets		2,535.9		2,259.7
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance	[13]	2.8		4.3		14.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	4		7.1	[13]	0.2	[13]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0	[13]	0	[13]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	[13]	0	[13]
Settlements		(7.1)		(11.1)	[13]	(14.2)	[13]
Transfers into Level 3	[4],[5]	0		0	[13]	0	[13]
Transfers out of Level 3	[5]	0		0.1	[13]	0.8	[13]
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	7.9		2.4	[13]	2.8	[13]
Ending Balance		7.6		2.8	[13]	4.3	[13]
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9.7		11.4
Total Assets		(30.5)		(0.9)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,469.2		1,277.4
Total Assets		1,469.2		1,277.4
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,048.7		967.4
Total Assets		1,088.1		980.2
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		9.1		3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		9.1		3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.5		0.2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	8.3		3.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	3.6		1.1
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(40.2)		(12.3)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(45.5)		(12.4)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	39.4		12.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	47.6		13.3
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	9.1		3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	1.5		0.2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.5		0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.3		$ 0.2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	20.52		19.68
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	195		48.55
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	33.80		36.34
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 8.6		$ 2.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 1.2		$ 0
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.36)		(7.90)
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	5.75		8.91
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	0.86		1.32
Ohio Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			$ 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		$ (119)		15.9		48.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(1.4)		(3)		0.5
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		7.4		6.2		(6.7)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(19.4)		(138.1)		(26.3)
Ending Balance		$ (132.4)		$ (119)		15.9
Ohio Power Co [Member] | Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]	0.08%		0.47%
Ohio Power Co [Member] | High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]	1.90%		3.40%
Ohio Power Co [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]	1.36%		2.72%
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			$ 27.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				27
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0.4
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Risk Management Assets
Risk Management Assets		$ 0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		132.4		119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.6		0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	132.4		119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.6		0.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	132.4		119
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 132.4		$ 119
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	30.52		30.14
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	170.43		71.85
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	44.62		47.45
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		$ 0.7		$ 0.6		(0.3)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	3.1		(1)		(0.2)
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		(3.8)		0.4		0.6
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	6.2		0.7		0.5
Ending Balance		6.2		0.7		0.6
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	6.4		0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(0.2)		(0.1)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(0.2)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.2		0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	6.4		0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.2
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		6.4		0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2		$ 0
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(6.62)		(7.99)
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	1.41		1.03
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.76)		(0.36)
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			$ 10.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				11.2
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		$ 0.7		0.8		(0.5)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	6		7.7		9.2
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		(6.8)		(8.4)		(8.7)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	6		0.6		0.8
Ending Balance		5.9		0.7		$ 0.8
Southwestern Electric Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			1.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				1.4
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			8.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				8.7
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0.3
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]			0
Risk Management Assets
Risk Management Assets		6.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.8
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	6.4		0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.2		0.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(0.6)		(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(0.6)		(0.1)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.3		0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0		0.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	6.7		0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.8		0.1
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[12]	2.37
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[12]	2.96
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[12]	2.62
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 6.7		0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.6		$ 0.1
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(6.62)		(7.99)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	1.41		1.03
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.76)		(0.36)
Cash [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1],[15]	$ 220.1		$ 211.7
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	36.9		32.8
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	183.2		173.8
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	0		5.1
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	0		0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,048.7		967.4
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,048.7		967.4
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,048.7		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
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,048.7		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
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[16]	102.9		91.7
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		102.9		91.7
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[17]	36.7		28.3
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[17]	0		0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[17]	36.7		28.3
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[17]	0		0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[17]	0		0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	17.2		18.7
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	9.7		11.4
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	7.5		7.3
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	17.2		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	[18]	9.7		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	[18]	7.5		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	[18]	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	[18]	0		0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		981.2		785.4
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		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
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		981.2		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
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		981.2		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
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		981.2		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
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		58.7		60.9
Corporate Debt [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		58.7		60.9
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		58.7		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
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		58.7		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
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8.8		121.1
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8.8		121.1
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8.8		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
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8.8		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
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,461.7		1,270.1
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,461.7		1,270.1
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,461.7		1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,461.7		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	[17]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	$ 0		$ 0
[1]	Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or 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 assets/liabilities 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 December 31, 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 periods 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. 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]	Represents market prices in dollars per MMBtu.
[13]	Includes both affiliated and nonaffiliated transactions.
[14]	Substantially comprised of power contracts.
[15]	Primarily represents amounts held for the repayment of debt.
[16]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[17]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[18]	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	12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Jun. 30, 2013	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 6,101.1
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1],[2]														(16.5)
Federal:
Current															(4)	$ (30.7)	$ 107.3
Deferred															856.6	(28.8)	774.8
Total Federal															901.2	(41.9)	882.1
State and Local:
Current															16	(10.5)	14.5
Deferred															44.9	(21.2)	23
Total State and Local															68.5	(31.8)	37.5
Income Tax Expense (Credit)															969.7	(73.7)	919.6
Income Tax Expense:
Deferred															901.5	(50)	808.2
Income Tax Expense (Credit)															969.7	(73.7)	919.6
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		$ 401.8	$ 556.7	$ 376.2	$ 594.2	$ 375.2		$ (764.2)	[3]	$ 503.9		$ 503.1			1,928.9	618	2,052.3
Discontinued Operations						0		0		2.5	[4]	0			0	2.5	(283.7)
Income Tax Expense (Credit)															969.7	(73.7)	919.6
Pretax Income															2,898.6	546.8	2,688.2
Income Taxes on Pretax Income at Statutory Rate (35%)															1,014.5	191.4	940.9
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															60.2	41.7	53.6
Investment Tax Credits, Net															(18.8)	(12.3)	(11.6)
State and Local Income Taxes, Net															54.7	(20.7)	24.4
Removal Costs															(32.7)	(39.8)	(28.8)
AFUDC															(37.4)	(44.8)	(51.6)
Valuation Allowance															(1.8)	(128.3)	17.2
U.K. Windfall Tax															0	(12.9)	0
Tax Reform Adjustments															(26.7)	0	0
Tax Adjustments															(35.8)	(43.9)	(20.1)
Other															(6.5)	(4.1)	(4.4)
Income Tax Expense (Credit)															$ 969.7	$ (73.7)	$ 919.6
Effective Income Tax Rate															33.50%	(13.50%)	34.20%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		3,504.6				2,753									$ 3,504.6	$ 2,753
Deferred Tax Liabilities		(10,318.5)				(14,637.4)									(10,318.5)	(14,637.4)
Property Related Temporary Differences		(5,680.6)				(8,758.1)									(5,680.6)	(8,758.1)
Amounts Due from Customers for Future Federal Income Taxes		1,064.8				(292.2)									1,064.8	(292.2)
Deferred State Income Taxes		(1,124.4)				(976.6)									(1,124.4)	(976.6)
Securitized Assets		(257.7)				(535.6)									(257.7)	(535.6)
Regulatory Assets		(500.3)				(896.9)									(500.3)	(896.9)
Deferred Income Taxes on Other Comprehensive Loss		25.7				88.7									25.7	88.7
Accrued Nuclear Decommissioning		(457)				(666.8)									(457)	(666.8)
Net Operating Loss Carryforward		86.6				101.2									86.6	101.2
Deferred Tax Assets, Tax Credit Carryforwards, General Business		174.7				45.1									174.7	45.1
Investment in Partnership		(222)				(349.6)									(222)	(349.6)
Valuation Allowance		0				(1.8)									0	(1.8)	$ 130
All Other, Net		76.3				358.2									76.3	358.2
Net Deferred Tax Liabilities		(6,813.9)				(11,884.4)									(6,813.9)	(11,884.4)
Net Income Tax Operating Loss Carryforwards
Federal Net Income Tax Operating Loss															230.1
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															1.7	2.7	2.7
Interest Income															6.1	9.9	0.8
Reversal of Prior Period Interest Expense															0	3.3	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		3.6				2.9									3.6	2.9
Accrual for Payment of Interest and Penalties		8.3				5.8									8.3	5.8
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					98.8							187			98.8	187	182
Increase - Tax Positions Taken During a Prior Period															4.5	86	5.4
Decrease - Tax Positions Taken During a Prior Period															(28)	(161.2)	(0.4)
Increase - Tax Positions Taken During the Current Year															3.4	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															7.9	(13)	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		86.6				98.8									86.6	98.8	187
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		10.5				15.8									$ 10.5	$ 15.8	$ 100.2
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Effect of Income Tax Reform on AEP's Other Business Operations															$ 103
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1],[2]														$ 16.5
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 969.7	$ (73.7)	$ 919.6
Interest Income															16	16.3	7.9
Net Income (Loss)		401.8	556.7	376.2	594.2	375.2		(764.2)	[3]	503.9		503.1			$ 1,928.9	618	$ 2,052.3
Period with No Change in Unrecognized Tax Benefits															12 months
Original Indiana Corporate Income Tax Rate															8.50%
Reduction In Indiana Corporate Tax Rate															0.50%
Reduced Indiana Corporate Income Tax Rate															6.50%
Indiana Corporate Tax Rate															4.90%
Reduction In Income Tax New Rate																	6.50%
Pre-2016 TX Income/Franchise Tax Rate															0.95%
New TX Income/Franchise Tax Rate															0.75%
Anticipated TX Income/Franchise Tax Rate															1.00%
Valuation Allowance		0				(1.8)									$ 0	(1.8)	$ 130
Transmission and Distribution Expenses Net Income Adjustment																21
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%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate															7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate															9.50%
AEP Texas Inc. [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 807.1
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1],[5]														(117.4)
Federal:
Current															(85.7)	40.9	61.4
Deferred															63.3	29.9	(7.1)
Total Federal															(24)	69.1	52.6
State and Local:
Current															0.6	(8.8)	5.6
Deferred															0	(0.4)	0
Total State and Local															0.6	(9.2)	5.6
Income Tax Expense (Credit)															(23.4)	59.9	58.2
Income Tax Expense:
Deferred															63.3	29.5	(7.1)
Income Tax Expense (Credit)															(23.4)	59.9	58.2
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		163.9	64.3	49	33.3	55.8		8.1		49		33.7			310.5	146.6	120.3
Discontinued Operations						(0.6)	[6]	47.4	[6]	0.7	[6]	1.3	[6]		0	48.8	1.4
Income Tax Expense (Credit)															(23.4)	59.9	58.2
Pretax Income															287.1	255.3	179.9
Income Taxes on Pretax Income at Statutory Rate (35%)															100.5	89.4	63
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															0.7	0.5	0.5
Investment Tax Credits, Net															(1.6)	(1.7)	(1.7)
State and Local Income Taxes, Net															0.4	(6)	3.6
Parent Company Loss Benefit															0	(2.5)	(3.1)
U.K. Windfall Tax															0	(12.9)	0
Tax Reform Adjustments															(117.4)	0	0
Tax Adjustments															(4.2)	(4.9)	(1.6)
Other															(1.8)	(2)	(2.5)
Income Tax Expense (Credit)															$ (23.4)	$ 59.9	$ 58.2
Effective Income Tax Rate															(8.20%)	23.50%	32.40%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		221				135.8									$ 221	$ 135.8
Deferred Tax Liabilities		(1,134.1)				(1,667.5)									(1,134.1)	(1,667.5)
Property Related Temporary Differences		(791.5)				(1,056.1)									(791.5)	(1,056.1)
Amounts Due from Customers for Future Federal Income Taxes		140.9				(5.7)									140.9	(5.7)
Deferred State Income Taxes		(27.5)				(24.2)									(27.5)	(24.2)
Securitized Assets		(190.5)				(407)									(190.5)	(407)
Regulatory Assets		(36.4)				(61.3)									(36.4)	(61.3)
Deferred Income Taxes on Other Comprehensive Loss		4.1				8									4.1	8
Deferred Revenue		10.9				18									10.9	18
All Other, Net		(23.1)				(3.4)									(23.1)	(3.4)
Net Deferred Tax Liabilities		(913.1)				(1,531.7)									(913.1)	(1,531.7)
Net Income Tax Operating Loss Carryforwards
Federal Net Income Tax Operating Loss															261.8
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0	0	$ 0.2
Interest Income															1.1	0.2	0.2
Reversal of Prior Period Interest Expense															0	0.8	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		2.8				2.1									2.8	2.1
Accrual for Payment of Interest and Penalties		0.1				0.3									0.1	0.3
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					6.5							27.8			6.5	27.8	22.6
Increase - Tax Positions Taken During a Prior Period															2	6.5	5.2
Decrease - Tax Positions Taken During a Prior Period															(12.3)	(15)	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															3	(12.8)	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		(0.8)				6.5									(0.8)	6.5	27.8
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		(0.5)				4.2									$ (0.5)	4.2	26
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1],[5]														$ 117.4
Discontinued Operations																$ (27.5)	$ (1.7)
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ (23.4)	$ 59.9	$ 58.2
Net Income (Loss)		163.9	64.3	49	33.3	55.8		8.1		49		33.7			$ 310.5	146.6	120.3
Period with No Change in Unrecognized Tax Benefits															12 months
Transmission and Distribution Expenses Net Income Adjustment																7
AEP Transmission Co [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 558.6
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														0.6
Federal:
Current															(127.5)	(129.4)	(126.3)
Deferred															256	205.9	171.3
Total Federal															128.5	76.5	45
State and Local:
Current															1.9	0.4	3.1
Deferred															16.8	17.2	11.9
Total State and Local															18.7	17.6	15
Income Tax Expense (Credit)															147.2	94.1	60
Income Tax Expense:
Deferred															272.8	223.1	183.2
Income Tax Expense (Credit)															147.2	94.1	60
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		61.8	59.9	107.4	57	39.7		52.4		74.8		25.8			286.1	192.7	132.9
Discontinued Operations						0		0		0		0
Income Tax Expense (Credit)															147.2	94.1	60
Pretax Income															433.3	286.8	192.9
Income Taxes on Pretax Income at Statutory Rate (35%)															151.7	100.4	67.5
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
State and Local Income Taxes, Net															12.2	11.4	9.8
AFUDC															(18.3)	(18.3)	(18.6)
Tax Reform Adjustments															0.6	0	0
Other															1	0.6	1.3
Income Tax Expense (Credit)															$ 147.2	$ 94.1	$ 60
Effective Income Tax Rate															34.00%	32.80%	31.10%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		162.7				61.4									$ 162.7	$ 61.4
Deferred Tax Liabilities		(764.4)				(923.5)									(764.4)	(923.5)
Property Related Temporary Differences		(654.7)				(825.6)									(654.7)	(825.6)
Amounts Due from Customers for Future Federal Income Taxes		89.7				(37.2)									89.7	(37.2)
Deferred State Income Taxes		(77.4)				(55.6)									(77.4)	(55.6)
Deferred Federal Income Taxes on Deferred State Income Taxes		16.3				19.5									16.3	19.5
Net Operating Loss Carryforward		16.8				33.3									16.8	33.3
Deferred Tax Assets, Tax Credit Carryforwards, General Business		0.3				0									0.3	0
Valuation Allowance		0				0.1									0	0.1
All Other, Net		7.3				3.4									7.3	3.4
Net Deferred Tax Liabilities		(601.7)				(862.1)									(601.7)	(862.1)
Net Income Tax Operating Loss Carryforwards
Federal Net Income Tax Operating Loss															344.1
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0	0	$ 0
Interest Income															0	0	0
Reversal of Prior Period Interest Expense															0	0	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		0				0									0	0
Accrual for Payment of Interest and Penalties		0				0									0	0
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					0							0			0	0	0
Increase - Tax Positions Taken During a Prior Period															0	0	0
Decrease - Tax Positions Taken During a Prior Period															0	0	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															0	0	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		0				0									0	0	0
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		0				0									$ 0	$ 0	$ 0
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														$ (0.6)
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 147.2	$ 94.1	$ 60
Net Income (Loss)		61.8	59.9	107.4	57	39.7		52.4		74.8		25.8			$ 286.1	192.7	$ 132.9
Period with No Change in Unrecognized Tax Benefits															12 months
Original Indiana Corporate Income Tax Rate															8.50%
Reduction In Indiana Corporate Tax Rate															0.50%
Reduced Indiana Corporate Income Tax Rate															6.50%
Indiana Corporate Tax Rate															4.90%
Reduction In Income Tax New Rate																	6.50%
Valuation Allowance		0				0.1									$ 0	0.1
Appalachian Power Co [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															1,296.4
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														5.7
Federal:
Current															15.3	64.1
Deferred															166.9	125.8
Deferred Investment Tax Credits																	$ (0.3)
Total Federal															182.1	189.8
State and Local:
Current															(1.4)	4.4
Deferred															4.6	4.9
Deferred Investment Tax Credits																	(0.3)
Total State and Local															3.2	9.3
Income Tax Expense (Credit)															185.3	199.1	194.3
Income Tax Expense:
Current																	(32.9)
Deferred															171.5	130.7	227.5
Deferred Investment Tax Credits																	(0.3)
Income Tax Expense (Credit)															185.3	199.1	194.3
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		82.6	86	52.1	110.6	65.3		104.1		73.4		126.3			331.3	369.1	340.6
Discontinued Operations						0		0		0		0
Income Tax Expense (Credit)															185.3	199.1	194.3
Pretax Income															516.6	568.2	534.9
Income Taxes on Pretax Income at Statutory Rate (35%)															180.8	198.9	187.2
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															18	19.3	19.8
Investment Tax Credits, Net															(0.1)	(0.1)	(0.3)
State and Local Income Taxes, Net															3.5	6	7.2
Removal Costs															(12.4)	(12)	(9.9)
AFUDC															(5)	(6.1)	(7)
Valuation Allowance															0	(1.7)	1.7
Tax Reform Adjustments															4.3	0	0
Other															(3.8)	(5.2)	(4.4)
Income Tax Expense (Credit)															$ 185.3	$ 199.1	$ 194.3
Effective Income Tax Rate															35.90%	35.00%	36.30%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		614.4				413.5									$ 614.4	$ 413.5
Deferred Tax Liabilities		(2,180.1)				(3,085.8)									(2,180.1)	(3,085.8)
Property Related Temporary Differences		(1,308.2)				(2,031.9)									(1,308.2)	(2,031.9)
Amounts Due from Customers for Future Federal Income Taxes		228				(73.1)									228	(73.1)
Deferred State Income Taxes		(335.7)				(319.3)									(335.7)	(319.3)
Securitized Assets		(59.3)				(106.9)									(59.3)	(106.9)
Regulatory Assets		(83.9)				(159.9)									(83.9)	(159.9)
Deferred Income Taxes on Other Comprehensive Loss		(0.4)				4.5									(0.4)	4.5
Deferred Tax Assets, Tax Credit Carryforwards, General Business		16.6				11.7									16.6	11.7
All Other, Net		(22.8)				2.6									(22.8)	2.6
Net Deferred Tax Liabilities		(1,565.7)				(2,672.3)									(1,565.7)	(2,672.3)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0.5	0	$ 0.4
Interest Income															0	0.1	0
Reversal of Prior Period Interest Expense															0	0	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		0				0									0	0
Accrual for Payment of Interest and Penalties		1				0.1									1	0.1
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					0							0.3			0	0.3	0
Increase - Tax Positions Taken During a Prior Period															0	0	0.3
Decrease - Tax Positions Taken During a Prior Period															0	(0.3)	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															0	0	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		0				0									0	0	0.3
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		0				0									$ 0	$ 0	$ 0.2
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														$ (5.7)
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 185.3	$ 199.1	$ 194.3
Net Income (Loss)		82.6	86	52.1	110.6	65.3		104.1		73.4		126.3			$ 331.3	369.1	340.6
Period with No Change in Unrecognized Tax Benefits															12 months
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%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate															7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate															9.50%
Indiana Michigan Power Co [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 808.7
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														2.3
Federal:
Current															(106.5)	(44.8)
Deferred															202.1	104.9
Deferred Investment Tax Credits																	(3.3)
Total Federal															90.9	63.9
State and Local:
Current															(8.1)	3.4
Deferred															(1.4)	0.2
Deferred Investment Tax Credits																	(3.3)
Total State and Local															(9.5)	3.6
Income Tax Expense (Credit)															81.4	67.5	96.1
Income Tax Expense:
Current																	5.2
Deferred															200.7	105.1	94.2
Deferred Investment Tax Credits																	(3.3)
Income Tax Expense (Credit)															81.4	67.5	96.1
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		42.9	64.9	10.5	68.4	38.5		75.4		51.3		74.7			186.7	239.9	204.8
Discontinued Operations						0		0		0		0
Income Tax Expense (Credit)															81.4	67.5	96.1
Pretax Income															268.1	307.4	300.9
Income Taxes on Pretax Income at Statutory Rate (35%)															93.8	107.6	105.3
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															11.4	6.7	9.5
Investment Tax Credits, Net															(4.7)	(4.7)	(3.3)
State and Local Income Taxes, Net															(1)	2.4	5.8
Removal Costs															(13.3)	(21.3)	(12.6)
AFUDC															(5.6)	(7.3)	(6.2)
Tax Reform Adjustments															(2.9)	0	0
Tax Adjustments															2.7	(14.2)	(4.2)
Other															1	(1.7)	1.8
Income Tax Expense (Credit)															$ 81.4	$ 67.5	$ 96.1
Effective Income Tax Rate															30.40%	22.00%	31.90%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		1,096.4				912.9									$ 1,096.4	$ 912.9
Deferred Tax Liabilities		(2,050.2)				(2,440.3)									(2,050.2)	(2,440.3)
Property Related Temporary Differences		(403)				(579.4)									(403)	(579.4)
Amounts Due from Customers for Future Federal Income Taxes		137.6				(50.4)									137.6	(50.4)
Deferred State Income Taxes		(180.6)				(158.7)									(180.6)	(158.7)
Regulatory Assets		(43.8)				(81)									(43.8)	(81)
Deferred Income Taxes on Other Comprehensive Loss		3.9				8.8									3.9	8.8
Accrued Nuclear Decommissioning		(457)				(666.8)									(457)	(666.8)
Net Operating Loss Carryforward		1.6				7.1									1.6	7.1
All Other, Net		(12.5)				(7)									(12.5)	(7)
Net Deferred Tax Liabilities		(953.8)				(1,527.4)									(953.8)	(1,527.4)
Net Income Tax Operating Loss Carryforwards
Federal Net Income Tax Operating Loss															332.6
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0	0.2	$ 0.2
Interest Income															1	0	0
Reversal of Prior Period Interest Expense															0	0	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		0				0									0	0
Accrual for Payment of Interest and Penalties		1.3				0.9									1.3	0.9
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					3.8							2.4			3.8	2.4	2.3
Increase - Tax Positions Taken During a Prior Period															0.2	1.8	0.1
Decrease - Tax Positions Taken During a Prior Period															(0.5)	(0.4)	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															(0.3)	0	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		3.2				3.8									3.2	3.8	2.4
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		2.1				2.5									$ 2.1	$ 2.5	$ 1.6
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														$ (2.3)
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 81.4	$ 67.5	$ 96.1
Net Income (Loss)		42.9	64.9	10.5	68.4	38.5		75.4		51.3		74.7			$ 186.7	239.9	$ 204.8
Period with No Change in Unrecognized Tax Benefits															12 months
Original Indiana Corporate Income Tax Rate															8.50%
Reduction In Indiana Corporate Tax Rate															0.50%
Reduced Indiana Corporate Income Tax Rate															6.50%
Indiana Corporate Tax Rate															4.90%
Reduction In Income Tax New Rate																	6.50%
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%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate															7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate															9.50%
Ohio Power Co [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 743.1
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1],[5]														(14.3)
Federal:
Current															11.2	178.8
Deferred															141.3	(40.8)
Deferred Investment Tax Credits																	$ (0.1)
Total Federal															152.5	138
State and Local:
Current															0.2	4.2
Deferred															6.6	1.6
Deferred Investment Tax Credits																	(0.1)
Total State and Local															6.8	5.8
Income Tax Expense (Credit)															159.3	143.8	126.5
Income Tax Expense:
Current																	89
Deferred															147.9	(39.2)	37.6
Deferred Investment Tax Credits																	(0.1)
Income Tax Expense (Credit)															159.3	143.8	126.5
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		92.8	82.6	62.3	86.2	37.5		99.9		74.6		70.2			323.9	282.2	232.7
Discontinued Operations						0		0		0		0
Income Tax Expense (Credit)															159.3	143.8	126.5
Pretax Income															483.2	426	359.2
Income Taxes on Pretax Income at Statutory Rate (35%)															169.1	149.1	125.7
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															7.6	7.1	8.2
Investment Tax Credits, Net															0	0	(0.1)
State and Local Income Taxes, Net															4.4	3.8	0.7
Tax Reform Adjustments															(14.4)	0	0
Other															(7.4)	(16.2)	(8)
Income Tax Expense (Credit)															$ 159.3	$ 143.8	$ 126.5
Effective Income Tax Rate															33.00%	33.80%	35.20%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		286				232.4									$ 286	$ 232.4
Deferred Tax Liabilities		(1,048.9)				(1,578.5)									(1,048.9)	(1,578.5)
Property Related Temporary Differences		(761.2)				(1,090.8)									(761.2)	(1,090.8)
Amounts Due from Customers for Future Federal Income Taxes		127.3				(43.6)									127.3	(43.6)
Deferred State Income Taxes		(41.7)				(34.6)									(41.7)	(34.6)
Regulatory Assets		(107.7)				(174.1)									(107.7)	(174.1)
Deferred Income Taxes on Other Comprehensive Loss		(0.6)				(1.6)									(0.6)	(1.6)
Deferred Fuel and Purchased Power		(24.5)				(117.6)									(24.5)	(117.6)
All Other, Net		45.5				116.2									45.5	116.2
Net Deferred Tax Liabilities		(762.9)				(1,346.1)									(762.9)	(1,346.1)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0	0.2	$ 1
Interest Income															1.6	0	0
Reversal of Prior Period Interest Expense															0	0	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		0.3				0									0.3	0
Accrual for Payment of Interest and Penalties		1				1.7									1	1.7
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					6.9							6.9			6.9	6.9	6.9
Increase - Tax Positions Taken During a Prior Period															0	0	0
Decrease - Tax Positions Taken During a Prior Period															0	0	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															0	0	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		6.9				6.9									6.9	6.9	6.9
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		4.5				4.4									$ 4.5	$ 4.4	$ 4.5
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1],[5]														$ 14.3
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 159.3	$ 143.8	$ 126.5
Net Income (Loss)		92.8	82.6	62.3	86.2	37.5		99.9		74.6		70.2			$ 323.9	282.2	232.7
Period with No Change in Unrecognized Tax Benefits															12 months
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%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate															7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate															9.50%
Public Service Co Of Oklahoma [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 538.6
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														2.8
Federal:
Current															(77.1)	(28)
Deferred															122.7	77.2
Deferred Investment Tax Credits																	(0.6)
Total Federal															44	47.8
State and Local:
Current															(0.2)	(1.9)
Deferred															2	5.3
Deferred Investment Tax Credits																	(0.6)
Total State and Local															6.1	6.6
Income Tax Expense (Credit)															50.1	54.4	51.3
Income Tax Expense:
Current																	(6.4)
Deferred															124.7	82.5	58.3
Deferred Investment Tax Credits																	(0.6)
Income Tax Expense (Credit)															50.1	54.4	51.3
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		0.6	46.2	20.4	4.8	2.6		52.8		28.9		15.7			72	100	92.5
Discontinued Operations						0		0		0		0
Income Tax Expense (Credit)															50.1	54.4	51.3
Pretax Income															122.1	154.4	143.8
Income Taxes on Pretax Income at Statutory Rate (35%)															42.7	54	50.3
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															0.3	0.8	0.5
Investment Tax Credits, Net															(1.6)	(1.4)	(1.8)
State and Local Income Taxes, Net															4	4.2	5.1
AFUDC															(0.2)	(2.2)	(3.1)
Tax Reform Adjustments															2.8	0	0
Other															2.1	(1)	0.3
Income Tax Expense (Credit)															$ 50.1	$ 54.4	$ 51.3
Effective Income Tax Rate															41.00%	35.20%	35.70%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		269.2				153.8									$ 269.2	$ 153.8
Deferred Tax Liabilities		(911.2)				(1,212.6)									(911.2)	(1,212.6)
Property Related Temporary Differences		(623.8)				(927.3)									(623.8)	(927.3)
Amounts Due from Customers for Future Federal Income Taxes		111.6				(3.2)									111.6	(3.2)
Deferred State Income Taxes		(142.7)				(128.5)									(142.7)	(128.5)
Regulatory Assets		(34.4)				(67.6)									(34.4)	(67.6)
Deferred Income Taxes on Other Comprehensive Loss		(0.8)				(1.8)									(0.8)	(1.8)
Deferred Federal Income Taxes on Deferred State Income Taxes		33.5				50.6									33.5	50.6
Net Operating Loss Carryforward		23.1				16.5									23.1	16.5
Deferred Tax Assets, Tax Credit Carryforwards, General Business		0.7				0									0.7	0
All Other, Net		(9.2)				2.5									(9.2)	2.5
Net Deferred Tax Liabilities		(642)				(1,058.8)									(642)	(1,058.8)
Net Income Tax Operating Loss Carryforwards
Federal Net Income Tax Operating Loss															213.9
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0	0	$ 0.1
Interest Income															0	0.3	0
Reversal of Prior Period Interest Expense															0	0.7	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		0.6				0.6									0.6	0.6
Accrual for Payment of Interest and Penalties		0				0									0	0
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					0.1							1.3			0.1	1.3	1.3
Increase - Tax Positions Taken During a Prior Period															0.1	0.1	0
Decrease - Tax Positions Taken During a Prior Period															(0.9)	(1.3)	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															0.7	0	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		0				0.1									0	0.1	1.3
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		0				0.1									$ 0	$ 0.1	$ 0.9
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														$ (2.8)
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 50.1	$ 54.4	$ 51.3
Net Income (Loss)		0.6	46.2	20.4	4.8	2.6		52.8		28.9		15.7			$ 72	100	92.5
Period with No Change in Unrecognized Tax Benefits															12 months
Pre-2016 TX Income/Franchise Tax Rate															0.95%
New TX Income/Franchise Tax Rate															0.75%
Anticipated TX Income/Franchise Tax Rate															1.00%
Transmission and Distribution Expenses Net Income Adjustment																2
Southwestern Electric Power Co [Member]
Federal Tax Reform [Abstract]
Decrease in Deferred Income Tax Liabilities															$ 782.9
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														0.7
Federal:
Current															(30.1)	(96.7)
Deferred															84.8	172.6
Deferred Investment Tax Credits																	(1.4)
Total Federal															53.3	74.7
State and Local:
Current															(0.9)	(12.6)
Deferred															(4.3)	(10)
Deferred Investment Tax Credits																	(1.4)
Total State and Local															(5.2)	(22.6)
Income Tax Expense (Credit)															48.1	52.1	84.8
Income Tax Expense:
Current																	44.3
Deferred															80.5	162.6	41.9
Deferred Investment Tax Credits																	(1.4)
Income Tax Expense (Credit)															48.1	52.1	84.8
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		11	84.1	25.1	17.3	16.5		84.4		44.3		24.5			137.5	169.7	196
Discontinued Operations						0		0		0		0
Income Tax Expense (Credit)															48.1	52.1	84.8
Pretax Income															185.6	221.8	280.8
Income Taxes on Pretax Income at Statutory Rate (35%)															65	77.6	98.3
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															1.9	3.2	3.1
Depletion															(5.7)	(5.5)	(5.5)
Investment Tax Credits, Net															(1.4)	(1.2)	(1.4)
State and Local Income Taxes, Net															(2.3)	(14.7)	4.8
AFUDC															(0.9)	(3.9)	(9.2)
Tax Reform Adjustments															(0.4)	0	0
Tax Adjustments															(9.9)	(0.9)	(3.9)
Other															1.8	(2.5)	(1.4)
Income Tax Expense (Credit)															$ 48.1	$ 52.1	$ 84.8
Effective Income Tax Rate															25.90%	23.50%	30.20%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		349.4				230.5									$ 349.4	$ 230.5
Deferred Tax Liabilities		(1,267.1)				(1,837.4)									(1,267.1)	(1,837.4)
Property Related Temporary Differences		(908.8)				(1,445.2)									(908.8)	(1,445.2)
Amounts Due from Customers for Future Federal Income Taxes		135.8				(48.2)									135.8	(48.2)
Deferred State Income Taxes		(189.2)				(175.1)									(189.2)	(175.1)
Regulatory Assets		(30.8)				(40.7)									(30.8)	(40.7)
Deferred Income Taxes on Other Comprehensive Loss		1.3				5.1									1.3	5.1
Impairment Loss		17.4				20.3									17.4	20.3
Net Operating Loss Carryforward		38.7				40.3									38.7	40.3
Deferred Tax Assets, Tax Credit Carryforwards, General Business		0.8				0.1									0.8	0.1
All Other, Net		17.1				36.5									17.1	36.5
Net Deferred Tax Liabilities		(917.7)				(1,606.9)									(917.7)	(1,606.9)
Net Income Tax Operating Loss Carryforwards
Federal Net Income Tax Operating Loss															87.6
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense															0	0	$ 0.4
Interest Income															0	0	0
Reversal of Prior Period Interest Expense															0	1.4	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest		0				0.1									0	0.1
Accrual for Payment of Interest and Penalties		0				0									0	0
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					1.3							9.3			1.3	9.3	7.5
Increase - Tax Positions Taken During a Prior Period															1.7	1.3	1.8
Decrease - Tax Positions Taken During a Prior Period															(5.4)	(9.3)	0
Increase - Tax Positions Taken During the Current Year															0	0	0
Decrease - Tax Positions Taken During the Current Year															0	0	0
Decrease - Settlements with Taxing Authorities															1.6	0	0
Decrease - Lapse of the Applicable Statute of Limitations															0	0	0
Balance at December 31,		(0.8)				1.3									(0.8)	1.3	9.3
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		(0.5)				0.8									$ (0.5)	$ 0.8	$ 6
Income Taxes (Textuals) [Abstract]
Future Statutory Tax Rate on Pretax Income															21.00%
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform	[1]														$ (0.7)
Statutory Tax Rate on Pretax Income															35.00%	35.00%	35.00%
Limit on Utiliization of Net Operating Losses Arising After December 31, 2017															80.00%
Income Tax Expense (Credit)															$ 48.1	$ 52.1	$ 84.8
Net Income (Loss)		11	$ 84.1	$ 25.1	$ 17.3	16.5		$ 84.4		$ 44.3		$ 24.5			$ 137.5	169.7	196
Period with No Change in Unrecognized Tax Benefits															12 months
Pre-2016 TX Income/Franchise Tax Rate															0.95%
New TX Income/Franchise Tax Rate															0.75%
Anticipated TX Income/Franchise Tax Rate															1.00%
Transmission and Distribution Expenses Net Income Adjustment																9
AEP Transmission Holdco's Equity Investment in ETT [Member]
Income Taxes (Textuals) [Abstract]
Excess Accumulated Deferred Income Taxes															$ 154
Arkansas [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		72													$ 72
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2022
Arkansas [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		71.2													$ 71.2
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2022
Kentucky [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		157.6													$ 157.6
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Louisiana [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		543.1													$ 543.1
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Louisiana [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		533.4													$ 533.4
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		799.8													$ 799.8
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Oklahoma [Member] | AEP Transmission Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		296.9													$ 296.9
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Oklahoma [Member] | Public Service Co Of Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		477													$ 477
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Tennessee [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		27.9													$ 27.9
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2032
Virginia [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		17.8													$ 17.8
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
West Virginia [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		29.2													$ 29.2
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
West Virginia [Member] | Indiana Michigan Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		14.1													$ 14.1
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Ohio Municipal [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		106.3													$ 106.3
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2022
Ohio Municipal [Member] | AEP Transmission Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		64.2													$ 64.2
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2022
Federal [Member]
Federal:
Deferred Investment Tax Credits															$ 48.6	17.6	0
State and Local:
Deferred Investment Tax Credits															48.6	17.6	0
Income Tax Expense:
Deferred Investment Tax Credits															48.6	17.6	0
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		4													$ 4
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount		174.7													$ 174.7
Tax Credit Carryforward Amount To Expire If Not Used		145.8													145.8
Income Taxes (Textuals) [Abstract]
Uncertain Tax Positions Netted Against Tax Credit and Alternative Minimum Tax Carryforward Tax Benefits		0				17									$ 0	17
Federal [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | AEP Texas Inc. [Member]
Federal:
Deferred Investment Tax Credits															$ (1.6)	(1.7)	(1.7)
State and Local:
Deferred Investment Tax Credits															(1.6)	(1.7)	(1.7)
Income Tax Expense:
Deferred Investment Tax Credits															(1.6)	(1.7)	(1.7)
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0.6													0.6
Tax Credit Carryforward Amount To Expire If Not Used		0.3													$ 0.3
Federal [Member] | AEP Texas Inc. [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | AEP Transmission Co [Member]
Federal:
Deferred Investment Tax Credits															$ 0	0	0
State and Local:
Deferred Investment Tax Credits															0	0	0
Income Tax Expense:
Deferred Investment Tax Credits															$ 0	0	$ 0
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0.3													$ 0.3
Tax Credit Carryforward Amount To Expire If Not Used		0.1													$ 0.1
Federal [Member] | AEP Transmission Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | AEP Transmission Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | Appalachian Power Co [Member]
Federal:
Deferred Investment Tax Credits															$ (0.1)	(0.1)
State and Local:
Deferred Investment Tax Credits															(0.1)	(0.1)
Income Tax Expense:
Deferred Investment Tax Credits															(0.1)	(0.1)
Tax Credit Carryforward
Tax Credit Carryforward, Amount		16.6													16.6
Tax Credit Carryforward Amount To Expire If Not Used		6.1													$ 6.1
Federal [Member] | Appalachian Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | Appalachian Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | Indiana Michigan Power Co [Member]
Federal:
Deferred Investment Tax Credits															$ (4.7)	3.8
State and Local:
Deferred Investment Tax Credits															(4.7)	3.8
Income Tax Expense:
Deferred Investment Tax Credits															$ (4.7)	3.8
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount		10.6													$ 10.6
Tax Credit Carryforward Amount To Expire If Not Used		10.1													$ 10.1
Federal [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | Ohio Power Co [Member]
Federal:
Deferred Investment Tax Credits															$ 0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	0
Tax Credit Carryforward
Tax Credit Carryforward, Amount		14.8													14.8
Tax Credit Carryforward Amount To Expire If Not Used		1													$ 1
Federal [Member] | Ohio Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | Ohio Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | Public Service Co Of Oklahoma [Member]
Federal:
Deferred Investment Tax Credits															$ (1.6)	(1.4)
State and Local:
Deferred Investment Tax Credits															(1.6)	(1.4)
Income Tax Expense:
Deferred Investment Tax Credits															$ (1.6)	(1.4)
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0.7													$ 0.7
Tax Credit Carryforward Amount To Expire If Not Used		0.7													$ 0.7
Federal [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Federal [Member] | Southwestern Electric Power Co [Member]
Federal:
Deferred Investment Tax Credits															$ (1.4)	(1.2)
State and Local:
Deferred Investment Tax Credits															(1.4)	(1.2)
Income Tax Expense:
Deferred Investment Tax Credits															$ (1.4)	$ (1.2)
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0.8													$ 0.8
Tax Credit Carryforward Amount To Expire If Not Used		0.7													$ 0.7
Federal [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2036
Federal [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2032
Uk Windfall Tax Issue [Member]
State and Local:
Income Tax Expense (Credit)														$ 80
Income Tax Expense:
Income Tax Expense (Credit)														80
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Income Tax Expense (Credit)														80
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Income Tax Expense (Credit)														80
Income Taxes (Textuals) [Abstract]
Income Tax Expense (Credit)														80
Interest Income														$ 43
Tax Increase Prevention Act of 2014 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																	50.00%
Tax Increase Prevention Act of 2014 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																	50.00%
Tax Increase Prevention Act of 2014 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																	50.00%
Tax Increase Prevention Act of 2014 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																	50.00%
Tax Increase Prevention Act of 2014 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																	50.00%
Protecting Americans from Tax Hikes Act of 2015 [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | AEP Texas Inc. [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | AEP Transmission Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension																50.00%
Bonus Depreciation Extension Phase Down 40																40.00%
Bonus Depreciation Extension Phase Down 30																30.00%
Solar Investment Tax Credit																30.00%
Net Tax Benefit [Member]
Income Taxes (Textuals) [Abstract]
Discontinued Operations															$ 0	$ 0	$ 6.2
Net Tax Benefit [Member] | AEP Texas Inc. [Member]
Income Taxes (Textuals) [Abstract]
Discontinued Operations															0	27.6	1.8
Expiration of Charitable Contribution Carryforward Deductions [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance						6										6	17
Income Taxes (Textuals) [Abstract]
Valuation Allowance						6										6	17
Investment in Operations of AEPRO [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance																	156
Income Taxes (Textuals) [Abstract]
Valuation Allowance																	156
Sale of AEPRO [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance																	48
Income Taxes (Textuals) [Abstract]
Valuation Allowance																	$ 48
2011 Audit Issue Settlement [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance						56										56
Income Taxes (Textuals) [Abstract]
Valuation Allowance						56										56
Certain Assets Held for Sale and 2015 Federal Income Tax Return [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance						66										66
Income Taxes (Textuals) [Abstract]
Valuation Allowance						$ 66										66
Reversal of Unrealized Capital Loss Carryforward [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance		2													2
Income Taxes (Textuals) [Abstract]
Valuation Allowance		2													2
Federal Tax Reform [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets	[2]														470.2
Increase (Decrease) in Regulatory Liabilities	[2]														5,614.4
Federal Tax Reform [Member] | AEP Texas Inc. [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															12.1
Increase (Decrease) in Regulatory Liabilities															677.6
Federal Tax Reform [Member] | AEP Transmission Co [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															66.9
Increase (Decrease) in Regulatory Liabilities															492.3
Federal Tax Reform [Member] | Appalachian Power Co [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															129.1
Increase (Decrease) in Regulatory Liabilities															1,173
Federal Tax Reform [Member] | Indiana Michigan Power Co [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															85.3
Increase (Decrease) in Regulatory Liabilities															725.7
Federal Tax Reform [Member] | Ohio Power Co [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															62.7
Increase (Decrease) in Regulatory Liabilities															666.1
Federal Tax Reform [Member] | Public Service Co Of Oklahoma [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															8.3
Increase (Decrease) in Regulatory Liabilities															533.1
Federal Tax Reform [Member] | Southwestern Electric Power Co [Member]
Federal Tax Reform [Abstract]
Increase (Decrease) in Other Regulatory Assets															69.8
Increase (Decrease) in Regulatory Liabilities															713.8
Deregulated Generation Assets and Deferred Fuel [Member] | AEP Texas Inc. [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(113)
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															113
Deregulated Generation Assets and Deferred Fuel [Member] | Ohio Power Co [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(16)
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															16
Net Regulatory Liability for Tax Reform [Member]
Income Taxes (Textuals) [Abstract]
Excess Accumulated Deferred Income Taxes															4,400
Incremental Liability for Tax Reform [Member]
Income Taxes (Textuals) [Abstract]
Excess Accumulated Deferred Income Taxes															1,200
Pretax Excess ADIT [Member]
Income Taxes (Textuals) [Abstract]
Excess Accumulated Deferred Income Taxes															4,400
Temporary Differences Associated with Depreciable Property [Member]
Income Taxes (Textuals) [Abstract]
Excess Accumulated Deferred Income Taxes															3,200
Remaining Excess ADIT [Member]
Income Taxes (Textuals) [Abstract]
Excess Accumulated Deferred Income Taxes															1,200
State and Local Jurisdiction [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															7.6	(0.1)
State and Local:
Deferred Investment Tax Credits															7.6	(0.1)
Income Tax Expense:
Deferred Investment Tax Credits															7.6	(0.1)
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance		5													5
Tax Credit Carryforward
Tax Credit Carryforward, Amount		31													31
Tax Credit Carryforward Amount To Expire If Not Used		31													31
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
Valuation Allowance		5													5
State and Local Jurisdiction [Member] | AEP Texas Inc. [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	0
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
State and Local Jurisdiction [Member] | AEP Transmission Co [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	0
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance		2													2
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
Valuation Allowance		2													2
State and Local Jurisdiction [Member] | Appalachian Power Co [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	0
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	0
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
State and Local Jurisdiction [Member] | Ohio Power Co [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	0
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
State and Local Jurisdiction [Member] | Public Service Co Of Oklahoma [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															4.3	3.2
State and Local:
Deferred Investment Tax Credits															4.3	3.2
Income Tax Expense:
Deferred Investment Tax Credits															4.3	3.2
Tax Credit Carryforward
Tax Credit Carryforward, Amount		31													31
Tax Credit Carryforward Amount To Expire If Not Used		31													31
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															10
State and Local Jurisdiction [Member] | Southwestern Electric Power Co [Member]
Federal Tax Reform [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															(10)
Federal:
Deferred Investment Tax Credits															0	0
State and Local:
Deferred Investment Tax Credits															0	0
Income Tax Expense:
Deferred Investment Tax Credits															0	$ 0
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		$ 0													0
Income Taxes (Textuals) [Abstract]
Increase(Decrease) in Income Tax Expense (Benefit) from Tax Reform															$ 10
[1]	In 2017, in contemplation of corporate federal tax reform, the Registrants adopted a method under Internal Revenue Section 162 for deducting repair and maintenance costs associated with transmission and distribution property. This change resulted in a decrease in state income tax expense of approximately $10 million that has been excluded from the tables above.
[2]	The effect of Tax Reform on AEP’s other business operations (other than the Registrant Subsidiaries), which primarily include unregulated activities in the Generation & Marketing segment, transmission operations reflected in the AEP Transmission Holdco segment and activities recorded in Corporate and Other, increased income tax expense for the year-ended December 31, 2017 by approximately $103 million.
[3]	Includes impairments for certain merchant generation assets (see Note 7).
[4]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[5]	AEP Texas and OPCo recorded favorable adjustments to income tax expense of approximately $113 million and $16 million related to previously owned deregulated generation assets and certain deferred fuel amounts, respectively.
[6]	Includes the transfer of the Wind Farms (see Note 7).

Leases (Details)

Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Lease Rental Costs
Net Lease Expense on Operating Leases		$ 231.3	$ 224.9		$ 292.6
Amortization of Capital Leases		66.3	93.7		108.5
Interest on Capital Leases		16.7	18.9		25.1
Total Lease Rental Costs		314.3	337.5		426.2	[1]
PP&E and Related Obligations Under Capital Leases
Generation		141.7	146.3
Other Property, Plant and Equipment		373.3	373.1
Total Property, Plant and Equipment Under Capital Leases		515	519.4
Accumulated Amortization		229	226.4
Net Property, Plant and Equipment Under Capital Leases		286	293
Noncurrent Liability		238.8	242.1
Liability Due Within One Year		59	63.4
Total Obligations Under Capital Leases		297.8	305.5
Future Minimum Lease Payments
Capital Leases, 2018		76.6
Capital Leases, 2019		60.4
Capital Leases, 2020		49.7
Capital Leases, 2021		42.6
Capital Leases, 2022		35.1
Capital Leases, Later Years		106.2
Capital Leases, Total Future Minimum Lease Payments		370.6
Less Estimated Interest Element on Capital Leases		72.8
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		297.8
Noncancelable Operating Leases, 2018		245.9
Noncancelable Operating Leases, 2019		237.9
Noncancelable Operating Leases, 2020		227.6
Noncancelable Operating Leases, 2021		210.7
Noncancelable Operating Leases, 2022		201.1
Noncancelable Operating Leases, Later Years		137.1
Noncancelable Operating Leases, Total Future Minimum Lease Payments		1,260.3
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		$ 43.2
Leases (Textuals) [Abstract]
Maximum Remaining Lease Term		14 years
Lease Expenses Related to Discontinued Operations					89
Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,018	[2]	$ 147.8
2,019	[2]	147.8
2,020	[2]	147.8
2,021	[2]	147.8
2,022	[2]	147.2
Total Future Minimum Lease Payments	[2]	$ 738.4
Leases (Textuals) [Abstract]
Lease Term		33 years
Boat and Barge Leases [Member]
Leases (Textuals) [Abstract]
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases		$ 50
Guarantor Obligations, Current Carrying Value		7
GuaranteeObligationsCurrentCarryingValueOtherLiabilitiesCurrent		1
GuaranteeObligationsCurrentCarryingValueOtherLiabilitiesNoncurrent		6
AEP Texas Inc. [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		10.5	9.8	[3]	8.1	[3]
Amortization of Capital Leases		4	3.4		2.9
Interest on Capital Leases		0.8	0.6		0.4
Total Lease Rental Costs		15.3	13.8		11.4
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		32.7	26.1
Total Property, Plant and Equipment Under Capital Leases		32.7	26.1
Accumulated Amortization		10	7.7
Net Property, Plant and Equipment Under Capital Leases		22.7	18.4
Noncurrent Liability		18.5	14.8
Liability Due Within One Year		4.2	3.6
Total Obligations Under Capital Leases		22.7	18.4
Future Minimum Lease Payments
Capital Leases, 2018		5.1
Capital Leases, 2019		4
Capital Leases, 2020		3.4
Capital Leases, 2021		3.1
Capital Leases, 2022		2.6
Capital Leases, Later Years		8.3
Capital Leases, Total Future Minimum Lease Payments		26.5
Less Estimated Interest Element on Capital Leases		3.8
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		22.7
Noncancelable Operating Leases, 2018		11.6
Noncancelable Operating Leases, 2019		10.7
Noncancelable Operating Leases, 2020		9.8
Noncancelable Operating Leases, 2021		8.9
Noncancelable Operating Leases, 2022		7.9
Noncancelable Operating Leases, Later Years		21.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		70.4
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		10
Leases (Textuals) [Abstract]
Lease Expenses Related to Discontinued Operations			1		1
AEP Transmission Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		1.7	0.9		0.5
Amortization of Capital Leases		0	0		0
Interest on Capital Leases		0	0		0
Total Lease Rental Costs		1.7	0.9		0.5
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		0.2	0
Total Property, Plant and Equipment Under Capital Leases		0.2	0
Accumulated Amortization		0	0
Net Property, Plant and Equipment Under Capital Leases		0.2	0
Noncurrent Liability		0.1	0
Liability Due Within One Year		0.1	0
Total Obligations Under Capital Leases		0.2	0
Future Minimum Lease Payments
Capital Leases, 2018		0.1
Capital Leases, 2019		0.1
Capital Leases, 2020		0
Capital Leases, 2021		0
Capital Leases, 2022		0
Capital Leases, Later Years		0
Capital Leases, Total Future Minimum Lease Payments		0.2
Less Estimated Interest Element on Capital Leases		0
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		0.2
Noncancelable Operating Leases, 2018		1.7
Noncancelable Operating Leases, 2019		1.3
Noncancelable Operating Leases, 2020		1
Noncancelable Operating Leases, 2021		0.4
Noncancelable Operating Leases, 2022		0
Noncancelable Operating Leases, Later Years		0
Noncancelable Operating Leases, Total Future Minimum Lease Payments		4.4
Appalachian Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		17.5	16.6		16.4
Amortization of Capital Leases		6.9	6.4		5.6
Interest on Capital Leases		3.7	3.5		0.8
Total Lease Rental Costs		28.1	26.5		22.8
PP&E and Related Obligations Under Capital Leases
Generation		42.5	45
Other Property, Plant and Equipment		18	18.1
Total Property, Plant and Equipment Under Capital Leases		60.5	63.1
Accumulated Amortization		19	18.1
Net Property, Plant and Equipment Under Capital Leases		41.5	45
Noncurrent Liability		34.9	38.2
Liability Due Within One Year		6.6	6.8
Total Obligations Under Capital Leases		41.5	45
Future Minimum Lease Payments
Capital Leases, 2018		10
Capital Leases, 2019		7.9
Capital Leases, 2020		7
Capital Leases, 2021		6.8
Capital Leases, 2022		6.4
Capital Leases, Later Years		18.8
Capital Leases, Total Future Minimum Lease Payments		56.9
Less Estimated Interest Element on Capital Leases		15.4
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		41.5
Noncancelable Operating Leases, 2018		17.3
Noncancelable Operating Leases, 2019		15.6
Noncancelable Operating Leases, 2020		14.4
Noncancelable Operating Leases, 2021		12
Noncancelable Operating Leases, 2022		10.9
Noncancelable Operating Leases, Later Years		23.3
Noncancelable Operating Leases, Total Future Minimum Lease Payments		93.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		8.8
Indiana Michigan Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		88.4	90.5		88.3
Amortization of Capital Leases		11.1	35.6		40.7
Interest on Capital Leases		3.2	3.7		3.3
Total Lease Rental Costs		102.7	129.8		132.3
PP&E and Related Obligations Under Capital Leases
Generation		27.2	26.4
Other Property, Plant and Equipment		34	43.7
Total Property, Plant and Equipment Under Capital Leases		61.2	70.1
Accumulated Amortization		21.1	25.4
Net Property, Plant and Equipment Under Capital Leases		40.1	44.7
Noncurrent Liability		34.3	35.3
Liability Due Within One Year		5.8	9.4
Total Obligations Under Capital Leases		40.1	44.7
Future Minimum Lease Payments
Capital Leases, 2018		11
Capital Leases, 2019		7.2
Capital Leases, 2020		6.4
Capital Leases, 2021		5.9
Capital Leases, 2022		5.4
Capital Leases, Later Years		25.2
Capital Leases, Total Future Minimum Lease Payments		61.1
Less Estimated Interest Element on Capital Leases		21
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		40.1
Noncancelable Operating Leases, 2018		91.3
Noncancelable Operating Leases, 2019		90.3
Noncancelable Operating Leases, 2020		86.9
Noncancelable Operating Leases, 2021		82.4
Noncancelable Operating Leases, 2022		81.4
Noncancelable Operating Leases, Later Years		16.3
Noncancelable Operating Leases, Total Future Minimum Lease Payments		448.6
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.3
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,018		73.9
2,019		73.9
2,020		73.9
2,021		73.9
2,022		73.6
Total Future Minimum Lease Payments		$ 369.2
Leases (Textuals) [Abstract]
Lease Term		33 years
Indiana Michigan Power Co [Member] | Nuclear Fuel Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,018		$ 2
Leases (Textuals) [Abstract]
Lease Term		54 months
Portion of Unamortized Nuclear Fuel Inventory Sold at Cost		$ 110
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Leases (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars		$ 7
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 8
Ohio Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		8.2	7.1		7.6
Amortization of Capital Leases		4.1	4.2		3.9
Interest on Capital Leases		0.5	0.5		0.6
Total Lease Rental Costs		12.8	11.8		12.1
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		22.8	23.9
Total Property, Plant and Equipment Under Capital Leases		22.8	23.9
Accumulated Amortization		10.6	11.6
Net Property, Plant and Equipment Under Capital Leases		12.2	12.3
Noncurrent Liability		7.9	8.1
Liability Due Within One Year		4.3	4.2
Total Obligations Under Capital Leases		12.2	12.3
Future Minimum Lease Payments
Capital Leases, 2018		4.7
Capital Leases, 2019		2.4
Capital Leases, 2020		1.8
Capital Leases, 2021		1.6
Capital Leases, 2022		1.1
Capital Leases, Later Years		2
Capital Leases, Total Future Minimum Lease Payments		13.6
Less Estimated Interest Element on Capital Leases		1.4
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		12.2
Noncancelable Operating Leases, 2018		11.3
Noncancelable Operating Leases, 2019		10.3
Noncancelable Operating Leases, 2020		8.7
Noncancelable Operating Leases, 2021		6.3
Noncancelable Operating Leases, 2022		5.4
Noncancelable Operating Leases, Later Years		19.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		61.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		6.4
Public Service Co Of Oklahoma [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		4.4	5		5.4
Amortization of Capital Leases		4	3.7		3.5
Interest on Capital Leases		0.6	0.6		0.7
Total Lease Rental Costs		9	9.3		9.6
PP&E and Related Obligations Under Capital Leases
Generation		8.9	10
Other Property, Plant and Equipment		18	19.4
Total Property, Plant and Equipment Under Capital Leases		26.9	29.4
Accumulated Amortization		15.3	15.6
Net Property, Plant and Equipment Under Capital Leases		11.6	13.8
Noncurrent Liability		8.3	9.8
Liability Due Within One Year		3.5	4.1
Total Obligations Under Capital Leases		11.8	13.9
Future Minimum Lease Payments
Capital Leases, 2018		3.8
Capital Leases, 2019		2.5
Capital Leases, 2020		1.7
Capital Leases, 2021		1.3
Capital Leases, 2022		1
Capital Leases, Later Years		2.6
Capital Leases, Total Future Minimum Lease Payments		12.9
Less Estimated Interest Element on Capital Leases		1.3
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		11.6
Noncancelable Operating Leases, 2018		4.8
Noncancelable Operating Leases, 2019		4.3
Noncancelable Operating Leases, 2020		3.8
Noncancelable Operating Leases, 2021		2.9
Noncancelable Operating Leases, 2022		2.5
Noncancelable Operating Leases, Later Years		6.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		24.8
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.6
Southwestern Electric Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		5.3	6.7		6.7
Amortization of Capital Leases		11.2	13.6		13.7
Interest on Capital Leases		3.6	5.1		6.2
Total Lease Rental Costs		20.1	25.4		$ 26.6
PP&E and Related Obligations Under Capital Leases
Generation		33.4	34.5
Other Property, Plant and Equipment		122.4	122.1
Total Property, Plant and Equipment Under Capital Leases		155.8	156.6
Accumulated Amortization		94	86.5
Net Property, Plant and Equipment Under Capital Leases		61.8	70.1
Noncurrent Liability		57.8	65.5
Liability Due Within One Year		11.2	11.8
Total Obligations Under Capital Leases		69	$ 77.3
Future Minimum Lease Payments
Capital Leases, 2018		14.3
Capital Leases, 2019		12.7
Capital Leases, 2020		10.9
Capital Leases, 2021		10
Capital Leases, 2022		8.9
Capital Leases, Later Years		25.6
Capital Leases, Total Future Minimum Lease Payments		82.4
Less Estimated Interest Element on Capital Leases		13.4
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		69
Noncancelable Operating Leases, 2018		6
Noncancelable Operating Leases, 2019		5.7
Noncancelable Operating Leases, 2020		5.3
Noncancelable Operating Leases, 2021		4.9
Noncancelable Operating Leases, 2022		4.3
Noncancelable Operating Leases, Later Years		9.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		35.7
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.7
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Leases (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars		$ 8
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 10
[1]	Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statement of income in the amount of $89 million for the year ended December 31, 2015. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	AEP’s future minimum lease payments include equal shares from AEGCo and I&M.
[3]	Amounts include lease expenses related to AEP Texas Wind Farms that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for each of the years ended December 31, 2016 and 2015, respectively. See Note 7 for additional information.

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		Feb. 22, 2018	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Shares of Company
Beginning Balance, Shares			512,210,644	512,048,520	511,389,173		509,739,159
Issued				162,124	659,347		1,650,014
Ending Balance, Shares				512,210,644	512,048,520		511,389,173
Treasury Stock, Shares, Beginning Balance			20,205,046	20,336,592	20,336,592		20,336,592
Partners' Capital Account, Units, Treasury Units Reissued	[1]			(131,546)
Treasury Stock, Shares, Ending Balance				20,205,046	20,336,592		20,336,592
Long-term Debt
Senior Unsecured Notes				$ 16,478.3
Pollution Control Bonds	[2]			1,621.7	$ 1,725.1
Notes Payable	[3]			260.8	326.9
Securitization Bonds				1,416.5	1,705
Spent Nuclear Fuel Obligation	[4]			268.6	266.3
Other Long-term Debt				1,127.4	1,606.9
Total Long-term Debt Outstanding				21,173.3	20,256.4
Outstanding Long-term Debt
Principal Amount, 2018				1,753.7
Principal Amount, 2019				2,307.9
Principal Amount, 2020				1,322
Principal Amount, 2021				1,352.9
Principal Amount, 2022				1,318.4
Principal Amount, After 2022				13,265.7
Principal Amount, Total				21,320.6
Unamortized Discount, Net and Debt Issuance Costs				(147.3)
Total Long-term Debt Outstanding				21,173.3	20,256.4
Short-term Debt
Securitized Debt for Receivables	[5]			718	673
Commercial Paper				898.6	1,040
Notes Payable				22	0
Total Short-term Debt				$ 1,638.6	$ 1,713
Securitized Debt for Receivables	[5],[6]			1.22%	0.70%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable				1.22%	0.70%		0.30%
Net Uncollectible Accounts Receivable Written Off				$ 23.4	$ 23.7		$ 34.1
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts				925.5	945
Total Principal Outstanding				718	673
Delinquent Securitized Accounts Receivable				41.1	42.7
Bad Debt Reserves Related to Securitized Sale of Accounts Receivable				28.7	27.7
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable				303.2	322.1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				3,087.9	1,794.9		2,397.9
Proceeds from Issuance of Long-term Debt				3,854.1	2,594.9		3,436.6
Total Commitment From Bank Conduits To Finance Receivables				750
Reaquired Pollution Control Bonds Held by Trustees				$ 678
Maximum Percentage Debt to Capitalization				67.50%
Restricted Net Assets				$ 11,400
Retained Earnings Available to Pay Dividends				7,300
Dividend Restrictions	[7]			1,375.6
Dividends Paid on Common Stock				(1,191.9)	$ (1,121)		(1,059)
Credit Facilities, Total				3,000
Maximum Amount of Commercial Paper Outstanding				$ 1,600
Weighted Average Interest Rate of Commercial Paper Outstanding During Year				1.25%
Commercial Paper [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[6]			1.85%	1.02%
Loans Payable [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[6]			2.92%	0.00%
AEP Texas Inc. [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,932.2	$ 1,241.3
Pollution Control Bonds	[2]			490.5	530.3
Securitization Bonds				1,026.1	1,245.8
Other Long-term Debt				200.5	200.3
Total Long-term Debt Outstanding				3,649.3	3,217.7
Outstanding Long-term Debt
Principal Amount, 2018				266.1
Principal Amount, 2019				501.1
Principal Amount, 2020				377.7
Principal Amount, 2021				66.2
Principal Amount, 2022				493.1
Principal Amount, After 2022				1,970.5
Principal Amount, Total				3,674.7
Unamortized Discount, Net and Debt Issuance Costs				(25.4)
Total Long-term Debt Outstanding				3,649.3	3,217.7
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				323.1	428.7		273.7
Proceeds from Issuance of Long-term Debt				$ 749.6	199.2		370.1
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 219.6
Dividends Paid on Common Stock				0	(34)		$ (29)
AEP Texas Inc. [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				296	176.9
Maximum Loans to Money Pool				451.7	138.9
Average Borrowings from Money Pool				194.8	87.5
Average Loans to Money Pool				264.6	79.8
Net Loans (Borrowings) to/from Money Pool				103.5	(174.5)
Authorized Short Term Borrowing Limit				$ 400	$ 400
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.29%	0.88%		0.46%
Average Interest Rate For Funds Loaned				1.26%	0.72%		0.52%
AEP Texas Inc. [Member] | Nonutility [Member]
Maximum Interest Rate for Funds Borrowed				0.00%	1.11%		1.14%
Minimum Interest Rate For Funds Borrowed				0.00%	0.97%		0.64%
Maximum Interest Rate For Funds Loaned				1.85%	1.02%		0.00%
Minimum Interest Rate for Funds Loaned				0.00%	0.75%		0.00%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 0	$ 12.5	[8]
Maximum Loans to Money Pool				8.6	27	[8]
Average Borrowings from Money Pool				0	12	[8]
Average Loans to Money Pool				8.3	12.3	[8]
Net Loans (Borrowings) to/from Money Pool				$ 8.4	$ 8.6	[8]
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.00%	1.00%		0.76%
Average Interest Rate For Funds Loaned				1.32%	0.86%		0.00%
AEP Texas Inc. [Member] | Direct Borrowing [Member]
Maximum Interest Rate for Funds Borrowed				0.00%	0.98%		0.87%
Minimum Interest Rate For Funds Borrowed				0.00%	0.69%		0.37%
Maximum Interest Rate For Funds Loaned				0.00%	1.02%		0.00%
Minimum Interest Rate for Funds Loaned				0.00%	0.99%		0.00%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 0	$ 55	[9]
Maximum Loans to Money Pool				0	5	[9]
Average Borrowings from Money Pool				0	42.5	[9]
Average Loans to Money Pool				0	5	[9]
Borrowings from Parent				0	0	[9]
Loans to Parent				0	5	[9]
Authorized Short Term Borrowing Limit				$ 0	$ 0	[9]
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.00%	0.83%		0.48%
Average Interest Rate For Funds Loaned				0.00%	1.00%		0.00%
AEP Transmission Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,550.4	$ 1,932
Total Long-term Debt Outstanding				2,550.4	1,932
Outstanding Long-term Debt
Principal Amount, 2018				50
Principal Amount, 2019				85
Principal Amount, 2020				0
Principal Amount, 2021				50
Principal Amount, 2022				104
Principal Amount, After 2022				2,286
Principal Amount, Total				2,575
Unamortized Discount, Net and Debt Issuance Costs				(24.6)
Total Long-term Debt Outstanding				2,550.4	1,932
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				0	300		$ 0
Proceeds from Issuance of Long-term Debt				617.6	686.9		$ 449
Sub-Limit of Secured Debt				$ 50
Maximum Percentage of Consolidated Tangible Net Assets				10.00%
Tangible Capital to Tangible Assets				0.60%
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 0
AEP Transmission Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				467.2	363.4
Maximum Loans to Money Pool				268	82
Average Borrowings from Money Pool				180.5	153.7
Average Loans to Money Pool				119.8	14.6
Net Loans (Borrowings) to/from Money Pool				109.2	49.8
Authorized Short Term Borrowing Limit	[10]			$ 795	$ 795
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.36%	0.85%		0.46%
Average Interest Rate For Funds Loaned				1.27%	0.83%		0.49%
AEP Transmission Co [Member] | Direct Borrowing [Member]
Maximum Interest Rate for Funds Borrowed				1.85%	1.02%		0.87%
Minimum Interest Rate For Funds Borrowed				0.92%	0.69%		0.37%
Maximum Interest Rate For Funds Loaned				1.85%	1.02%		0.87%
Minimum Interest Rate for Funds Loaned				0.92%	0.69%		0.37%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 4.1	$ 5.6
Maximum Loans to Money Pool				151.9	170.4
Average Borrowings from Money Pool				1.1	1
Average Loans to Money Pool				39.3	35.7
Borrowings from Parent				1.1	1
Loans to Parent				22.5	14.2
Authorized Short Term Borrowing Limit	[11]			$ 75	$ 75
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.33%	0.83%		0.48%
Average Interest Rate For Funds Loaned				1.36%	0.87%		0.47%
Appalachian Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 3,045.1	$ 2,972.4
Pollution Control Bonds	[2]			512.2	615.8
Securitization Bonds				295.9	318.9
Other Long-term Debt				126.9	126.8
Total Long-term Debt Outstanding				3,980.1	4,033.9
Outstanding Long-term Debt
Principal Amount, 2018				249.2
Principal Amount, 2019				305.4
Principal Amount, 2020				90.3
Principal Amount, 2021				393
Principal Amount, 2022				26
Principal Amount, After 2022				2,951
Principal Amount, Total				4,014.9
Unamortized Discount, Net and Debt Issuance Costs				(34.8)
Total Long-term Debt Outstanding				3,980.1	4,033.9
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				136.2	142
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				5.6	6.7		$ 7.6
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,372.8	1,412.5		1,453.8
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				377.9	213.6		672.6
Proceeds from Issuance of Long-term Debt				320.9	314		$ 726.3
Reaquired Pollution Control Bonds Held by Trustees				$ 104
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 0
Appalachian Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				231.5	286.9
Maximum Loans to Money Pool				160.7	25.7
Average Borrowings from Money Pool				144.3	148
Average Loans to Money Pool				30	24.8
Net Loans (Borrowings) to/from Money Pool				(162.5)	(55.5)
Authorized Short Term Borrowing Limit				$ 600	$ 600
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.28%	0.80%		0.53%
Average Interest Rate For Funds Loaned				1.29%	0.82%		0.47%
Indiana Michigan Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,809	$ 1,512.8
Pollution Control Bonds	[2]			264.6	225.4
Notes Payable	[3]			188.6	251.4
Spent Nuclear Fuel Obligation	[4]			268.6	266.3
Other Long-term Debt				214.3	215.5
Total Long-term Debt Outstanding				2,745.1	2,471.4
Outstanding Long-term Debt
Principal Amount, 2018				474.7
Principal Amount, 2019				535.2
Principal Amount, 2020				26.4
Principal Amount, 2021				49.9
Principal Amount, 2022				3.5
Principal Amount, After 2022				1,673.9
Principal Amount, Total				2,763.6
Unamortized Discount, Net and Debt Issuance Costs				(18.5)
Total Long-term Debt Outstanding				2,745.1	2,471.4
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				136.5	136.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				6.7	7.1		$ 8.4
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,612.9	1,596.2		1,553
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				260.7	100.2		332.1
Proceeds from Issuance of Long-term Debt				$ 530.1	569.4		$ 310.7
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 416.2
Indiana Michigan Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				367.4	369.1
Maximum Loans to Money Pool				12.6	97.6
Average Borrowings from Money Pool				204.9	129.9
Average Loans to Money Pool				12.6	19.5
Net Loans (Borrowings) to/from Money Pool				(199.2)	(202.7)
Authorized Short Term Borrowing Limit				$ 500	$ 500
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.27%	0.80%		0.49%
Average Interest Rate For Funds Loaned				1.29%	0.80%		0.48%
Ohio Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,591.4	$ 1,590.2
Pollution Control Bonds	[2]			32.3	32.3
Securitization Bonds				94.5	140.2
Other Long-term Debt				1.1	1.2
Total Long-term Debt Outstanding				1,719.3	1,763.9
Outstanding Long-term Debt
Principal Amount, 2018				397
Principal Amount, 2019				48
Principal Amount, 2020				0.1
Principal Amount, 2021				500.1
Principal Amount, 2022				0.1
Principal Amount, After 2022				782.9
Principal Amount, Total				1,728.2
Unamortized Discount, Net and Debt Issuance Costs				(8.9)
Total Long-term Debt Outstanding				1,719.3	1,763.9
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				367.4	388.3
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				21.7	28.9		$ 30.7
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				2,339	2,633		2,569.4
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				46.4	395.9		$ 131.5
Reaquired Pollution Control Bonds Held by Trustees				345
Dividend Restrictions				0
Ohio Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				280.6	227.9
Maximum Loans to Money Pool				56.2	379.2
Average Borrowings from Money Pool				137	116.6
Average Loans to Money Pool				27.9	182.4
Net Loans (Borrowings) to/from Money Pool				(87.8)	24.2
Authorized Short Term Borrowing Limit				$ 400	$ 400
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.37%	0.85%		0.00%
Average Interest Rate For Funds Loaned				0.98%	0.74%		0.48%
Public Service Co Of Oklahoma [Member]
Shares of Company
Beginning Balance, Shares			10,482,000	10,482,000
Ending Balance, Shares				10,482,000	10,482,000
Long-term Debt
Senior Unsecured Notes				$ 1,144.1	$ 1,143.2
Pollution Control Bonds	[2]			12.6	12.6
Other Long-term Debt				129.8	130.2
Total Long-term Debt Outstanding				1,286.5	1,286
Outstanding Long-term Debt
Principal Amount, 2018				0.5
Principal Amount, 2019				375.5
Principal Amount, 2020				13.2
Principal Amount, 2021				250.5
Principal Amount, 2022				0.5
Principal Amount, After 2022				652.5
Principal Amount, Total				1,292.7
Unamortized Discount, Net and Debt Issuance Costs				(6.2)
Total Long-term Debt Outstanding				1,286.5	1,286
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				115.1	110.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				7	6.2		$ 5.8
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,337	1,269.3		1,326.1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				0.5	275.4		0.4
Proceeds from Issuance of Long-term Debt				$ 0	274.2		$ 248.8
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 173.5
Public Service Co Of Oklahoma [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				185.2	52
Maximum Loans to Money Pool				0	205.4
Average Borrowings from Money Pool				119.3	12.9
Average Loans to Money Pool				0	48.1
Net Loans (Borrowings) to/from Money Pool				(149.6)	(52)
Authorized Short Term Borrowing Limit				$ 300	$ 300
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.32%	0.96%		0.49%
Average Interest Rate For Funds Loaned				0.00%	0.83%		0.48%
Southwestern Electric Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,110.7	$ 2,359.2
Pollution Control Bonds	[2]			135.1	134.9
Notes Payable	[3]			72.1	75.3
Other Long-term Debt				124	109.7
Total Long-term Debt Outstanding				2,441.9	2,679.1
Outstanding Long-term Debt
Principal Amount, 2018				3.7
Principal Amount, 2019				457.2
Principal Amount, 2020				118.7
Principal Amount, 2021				3.7
Principal Amount, 2022				278.7
Principal Amount, After 2022				1,594.9
Principal Amount, Total				2,456.9
Unamortized Discount, Net and Debt Issuance Costs				(15)
Total Long-term Debt Outstanding				2,441.9	2,679.1
Short-term Debt
Notes Payable				22	0
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				138.2	130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				7.2	6.9		$ 7
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,563.4	1,531.7		1,597.8
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				353.7	3.3		306.8
Proceeds from Issuance of Long-term Debt				$ 114.6	406.7		445.9
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 470.6
Dividends Paid on Common Stock				(13.6)	(4.2)		$ (3.6)
Southwestern Electric Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				187.5	249.4
Maximum Loans to Money Pool				178.6	313.3
Average Borrowings from Money Pool				95.5	171.8
Average Loans to Money Pool				169.5	267.7
Net Loans (Borrowings) to/from Money Pool				(118.7)	167.8
Authorized Short Term Borrowing Limit				$ 350	$ 350
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.85%	1.02%		0.87%
Minimum Interest Rate				0.92%	0.69%		0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.28%	0.79%		0.53%
Average Interest Rate For Funds Loaned				0.98%	0.90%		0.48%
Southwestern Electric Power Co [Member] | Nonutility [Member]
Maximum Interest Rate for Funds Borrowed				0.00%	0.00%		0.00%
Minimum Interest Rate For Funds Borrowed				0.00%	0.00%		0.00%
Maximum Interest Rate For Funds Loaned				1.85%	1.02%		0.87%
Minimum Interest Rate for Funds Loaned				0.00%	0.69%		0.37%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 0	$ 0
Maximum Loans to Money Pool				2	2
Average Borrowings from Money Pool				0	0
Average Loans to Money Pool				2	2
Net Loans (Borrowings) to/from Money Pool				$ 2	$ 2
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.00%	0.00%		0.00%
Average Interest Rate For Funds Loaned				1.32%	0.82%		0.48%
Southwestern Electric Power Co [Member] | Loans Payable [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[6]			2.92%	0.00%
Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,047
Weighted Average Interest Rate				4.62%
Senior Notes [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.15%	1.65%
Senior Notes [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				8.13%	8.13%
Senior Notes [Member] | AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,047
Weighted Average Interest Rate				4.12%
Senior Notes [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.40%	2.61%
Senior Notes [Member] | AEP Texas Inc. [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.76%	6.76%
Senior Notes [Member] | AEP Transmission Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,047
Weighted Average Interest Rate				3.85%
Senior Notes [Member] | AEP Transmission Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.68%	2.68%
Senior Notes [Member] | AEP Transmission Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.52%	5.52%
Senior Notes [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,045
Weighted Average Interest Rate				5.20%
Senior Notes [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.30%	3.40%
Senior Notes [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				7.00%	7.00%
Senior Notes [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,047
Weighted Average Interest Rate				5.20%
Senior Notes [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.20%	3.20%
Senior Notes [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				7.00%	7.00%
Senior Notes [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,035
Weighted Average Interest Rate				5.98%
Senior Notes [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.375%	5.375%
Senior Notes [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.60%	6.60%
Senior Notes [Member] | Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,046
Weighted Average Interest Rate				4.80%
Senior Notes [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.05%	3.05%
Senior Notes [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.625%	6.625%
Senior Notes [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,045
Weighted Average Interest Rate				4.78%
Senior Notes [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.75%	2.75%
Senior Notes [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.45%	6.45%
Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[12]			2,017
Maturity Date High	[12]			2,042
Weighted Average Interest Rate				3.06%
Pollution Control Bonds [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.54%	0.69%
Pollution Control Bonds [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.30%	6.30%
Pollution Control Bonds [Member] | AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,030
Weighted Average Interest Rate				4.39%
Pollution Control Bonds [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.75%	4.00%
Pollution Control Bonds [Member] | AEP Texas Inc. [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.30%	6.30%
Pollution Control Bonds [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[12]			2,018
Maturity Date High	[12]			2,042
Weighted Average Interest Rate				2.44%
Pollution Control Bonds [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.625%	0.69%
Pollution Control Bonds [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.38%	5.38%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[12]			2,018
Maturity Date High	[12]			2,025
Weighted Average Interest Rate				2.02%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.75%	0.74%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.75%	4.625%
Pollution Control Bonds [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,038
Maturity Date High				2,038
Weighted Average Interest Rate				5.80%
Pollution Control Bonds [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.80%	5.80%
Pollution Control Bonds [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.80%	5.80%
Pollution Control Bonds [Member] | Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,020
Maturity Date High				2,020
Weighted Average Interest Rate				4.45%
Pollution Control Bonds [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.45%	4.45%
Pollution Control Bonds [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.45%	4.45%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,019
Weighted Average Interest Rate				3.62%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.60%	1.60%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.95%	4.95%
Notes Payable, Other Payables [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,032
Weighted Average Interest Rate				3.00%
Notes Payable, Other Payables [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.03%	1.456%
Notes Payable, Other Payables [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.37%	6.37%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,022
Weighted Average Interest Rate				2.15%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.03%	1.456%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.19%	1.81%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 2	$ 14
Notes Payable, Other Payables [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,024
Maturity Date High				2,032
Weighted Average Interest Rate				5.20%
Notes Payable, Other Payables [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.58%	4.58%
Notes Payable, Other Payables [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.37%	6.37%
Securitization Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]			2,017
Maturity Date High	[13]			2,028
Weighted Average Interest Rate				3.70%
Securitization Bonds [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.98%	0.88%
Securitization Bonds [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.31%	5.31%
Securitization Bonds [Member] | AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]			2,017
Maturity Date High	[13]			2,024
Weighted Average Interest Rate				4.05%
Securitization Bonds [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.98%	0.88%
Securitization Bonds [Member] | AEP Texas Inc. [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.31%	5.31%
Securitization Bonds [Member] | AEP Texas Inc. [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			96
Securitization Bonds [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]			2,023
Maturity Date High	[13]			2,028
Weighted Average Interest Rate				2.98%
Securitization Bonds [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.008%	2.008%
Securitization Bonds [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.772%	3.772%
Securitization Bonds [Member] | Appalachian Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		12
Securitization Bonds [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]			2,018
Maturity Date High	[13]			2,019
Weighted Average Interest Rate				2.049%
Securitization Bonds [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.049%	0.958%
Securitization Bonds [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.049%	2.049%
Securitization Bonds [Member] | Ohio Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			23
Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,059
Weighted Average Interest Rate				2.75%
Other Long Term Debt [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.15%	1.15%
Other Long Term Debt [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				13.718%	13.718%
Other Long Term Debt [Member] | AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,059
Weighted Average Interest Rate				2.76%
Other Long Term Debt [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.75%	2.438%
Other Long Term Debt [Member] | AEP Texas Inc. [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.50%	4.50%
Other Long Term Debt [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,026
Weighted Average Interest Rate				2.92%
Other Long Term Debt [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.73%	2.06%
Other Long Term Debt [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				13.718%	13.718%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,025
Weighted Average Interest Rate				3.03%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.82%	2.15%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.00%	6.00%
Other Long Term Debt [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,028
Maturity Date High				2,028
Weighted Average Interest Rate				1.15%
Other Long Term Debt [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.15%	1.15%
Other Long Term Debt [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.15%	1.15%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,027
Weighted Average Interest Rate				2.60%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.584%	1.92%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.00%	3.00%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,023
Weighted Average Interest Rate				3.00%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.925%	2.346%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.28%	4.28%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 2
Other Long Term Debt [Member] | Transource Energy [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Proceeds from Issuance of Long-term Debt			$ 2
Due Date			2,020
Senior Unsecured Notes Two [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Proceeds from Issuance of Long-term Debt			$ 450
Debt Instrument, Interest Rate, Stated Percentage			3.85%
Due Date			2,048
Includes Debt Included In Liabilities Held For Sale [Member]
Long-term Debt
Senior Unsecured Notes	[14]				$ 14,761
Total Long-term Debt Outstanding				$ 21,173.3	20,391.2	[14],[15]
Outstanding Long-term Debt
Total Long-term Debt Outstanding				$ 21,173.3	$ 20,391.2	[14],[15]
[1]	Reissued Treasury Stock used to fulfill share commitments related to AEP’s Share-based Compensation. See “Shared-based Compensation Plans” section of Note 15 for additional information.
[2]	For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series.
[3]	Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
[4]	Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).
[5]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[6]	Weighted average rate.
[7]	(a)Includes the restrictions of consolidated and unconsolidated subsidiaries.
[8]	(a)Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information.
[9]	(a)Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information.
[10]	(a)Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
[11]	(b)Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
[12]	Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.
[13]	Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.
[14]	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 7 for additional information.
[15]	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 7 for additional information.

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock Based Compensation (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		10,000,000
Number of Shares Remaining Available for Issuance Under the AEP Long-Term Incentive Plan		9,011,946
Reduction in Aggregate Common Shares Authorized Per Share Issued Pursuant to Stock Options or Stock Appreciation Rights		0.286
Performance Units [Member]
Performance Units
Awarded Units		590,700	597,400	575,000
Weighted Average Grant Date Fair Value, Granted		$ 69.78	$ 62.77	$ 59.19
Vesting Period (in years)		3 years	3 years	3 years
Certified Performance Scores and Units Earned
Certified Performance Score		164.80%	163.90%	176.30%
Performance Units Earned		956,055	1,111,966	1,202,107
Performance Units Manditorily Deferred as AEP Career Shares		20,213	9,963	41,707
Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program		47,177	51,684	54,074
Performance Units to be Paid in Cash		888,665	1,050,319	1,106,326
Cash Payouts
Cash Payouts for Performance Units		$ 64.9	$ 62.7	$ 48.1
Cash Payouts for AEP Career Share Distributions		$ 0	$ 9.1	$ 3
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 69.78	$ 62.77	$ 59.19
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		69.78	62.77	59.19
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 69.78	$ 62.77	$ 59.19
Stock Based Compensation (Textuals) [Abstract]
Performance Score by HR Committee, Lower Range		0.00%
Performance Score by HR Committee, Higher Range		200.00%
Equity Payouts For Career Share Distributions		$ 0.4	$ 0	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		2 years 10 months 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum		15.65%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum		27.19%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate		1.44%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate		0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Weighted Average Volatility Rate		19.07%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum		1.21%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum		1.48%
Restricted Stock Units (RSUs) [Member]
Stock Based Compensation (Textuals) [Abstract]
Maximum Contractual Term of Outstanding Restricted Stock Units (in months)		72 months
Performance Units and AEP Career Shares Reinvested Dividends Portion For [Member]
Performance Units
Awarded Units		74,600	89,200	103,600
Weighted Average Grant Date Fair Value, Granted		$ 72.35	$ 63.83	$ 54.35
Vesting Period	[1]	(b)	(b)	(b)
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 72.35	$ 63.83	$ 54.35
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		72.35	63.83	54.35
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 72.35	$ 63.83	$ 54.35
Restricted Shares and Restricted Stock Units [Member]
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested
Fair Value of Restricted Shares and Restricted Stock Units Vested		$ 16.1	$ 16.4	$ 18.3
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	[2]	$ 20	$ 21	$ 24.2
Restricted Stock [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 65.26	$ 62.88	$ 58.56
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		255,800	242,000	397,500
Weighted Average Grant Date Fair Value		$ 65.26	$ 62.88	$ 58.56
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		603,600
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 57.54
Shares/Units, Granted		255,800	242,000	397,500
Weighted Average Grant Date Fair Value, Granted		$ 65.26	$ 62.88	$ 58.56
Shares/Units, Vested		(295,100)
Weighted Average Grant Date Fair Value, Vested		$ 54.72
Shares/Units, Forfeited		(34,700)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 61.53
Nonvested, Shares/Units, Ending Balance		529,600	603,600
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 62.13	$ 57.54
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		255,800	242,000	397,500
Weighted Average Grant Date Fair Value		$ 65.26	$ 62.88	$ 58.56
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		255,800	242,000	397,500
Total Aggregate Intrinsic Value of Nonvested Shares		$ 39
Weighted Average Remaining Contractual Life of Nonvested Shares (in years)		1.6 years
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 70.79	$ 64.96	$ 55.46
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		14,800	19,100	24,900
Weighted Average Grant Date Fair Value		$ 70.79	$ 64.96	$ 55.46
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		14,800	19,100	24,900
Weighted Average Grant Date Fair Value, Granted		$ 70.79	$ 64.96	$ 55.46
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		14,800	19,100	24,900
Weighted Average Grant Date Fair Value		$ 70.79	$ 64.96	$ 55.46
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		14,800	19,100	24,900
Number of Years After Termination of Board Service Participant Can Elect to Have Stock Units Paid in Cash		10 years
Stock Based Compensation [Member]
Compensation Cost and Actual Tax Benefit Realized for the Tax Deductions from Compensation Cost for Share-based Payment Arrangements
Compensation Cost for Share-based Payment Arrangements	[3]	$ 79.5	$ 66.5	$ 63.8
Actual Tax Benefit Realized		18.9	23.3	22.3
Total Compensation Cost Capitalized		26.4	$ 20.8	$ 20.3
Stock Based Compensation (Textuals) [Abstract]
Total Unrecognized Compensation Cost Related to Unvested Share-based Compensation Arrangements Granted		$ 64
Weighted-average Period of Unrecognized Compensation Costs (in years)		1.35 years
Granted 2010 [Member] | Restricted Stock [Member] | Granted to Previous Chief Executive Officer Succession Candidates [Member] | August 3, 2013 through August 3, 2015 [Member]
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		165,520
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		165,520
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		165,520
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		165,520
[1]	(a)Awarded units in 2017 are mezzanine equity awards and awarded units in 2016 and 2015 are liability awards.
[2]	Intrinsic value is calculated as market price at exercise date.
[3]	(a)Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Affiliated Revenues and Purchases
Affiliated Revenues		$ 0	$ 0	$ 0
Indiana Michigan Power Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals)
Percentage of Power Sold under Unit Power Agreement		30.00%
AEP Generating Co to Indiana Michigan Power Co [Member]
Cook Coal Terminal
Coal Transloading Services		$ 10.2	12.8	15.8
Railcar Maintenance		$ 1.3	1.7	2
AEP Generating Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals)
Percentage of Power Sold under Unit Power Agreement		30.00%
AEP Generating Co to Public Service Co of Oklahoma [Member]
Cook Coal Terminal
Railcar Maintenance		$ 0.5	0.6	0.2
AEP Generating Co To Southwestern Electric Power Co [Member]
Cook Coal Terminal
Railcar Maintenance		3.5	3.3	2.8
AEP Energy Partners, Inc. to AEP Texas Inc. [Member]
Oklaunion PPA between AEP Texas and AEPEP [Abstract]
Oklaunion Purchase Power Agreement		64	74	77
Indiana Michigan Power Co to AEP Transmission Co [Member]
Joint License Agreement [Abstract]
Joint License Agreement		1.4	0.8	0.6
Kentucky Power Co to AEP Transmission Co [Member]
Joint License Agreement [Abstract]
Joint License Agreement		0.2	0.1	0
Ohio Power Co to AEP Transmission Co [Member]
Joint License Agreement [Abstract]
Joint License Agreement		2.4	2.3	2
Public Service Co of Oklahoma to AEP Transmission Co [Member]
Joint License Agreement [Abstract]
Joint License Agreement		0.3	0.2	0.3
AEP Generating Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		15.3	14.8	16.1
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0	0	0.1
AEP Generation Resources [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		0.1	0.3	4.9
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1.2	2	2.7
AEP River Operations LLC [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		0	0	15.5
AEP Transmission Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		580.5	367.5	225.6
Sales and Purchases of Property
Related Party Sales of Property		0	0	0.2
Related Party Purchases of Property		9.1	6.5	0.4
AEP Transmission Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
AEP Transmission Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0
AEP Transmission Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	0	0	0
AEP Transmission Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
AEP Transmission Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		572	366.1	225.6
AEP Transmission Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		8.5	0	0
Appalachian Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		172	142.1	147.8
Transmission Agreement
Net Charges from Transmission Agreement		158.2	103.2	92.7
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		37.2	36.9	37.7
Sales and Purchases of Property
Related Party Sales of Property		3.5	4.5	9.4
Related Party Purchases of Property		0.9	1.5	8.6
Appalachian Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		130.4	126	132.1
Appalachian Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0
Appalachian Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	1	9.2	10.6
Appalachian Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Appalachian Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		34.1	1.3	0.7
Appalachian Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		6.5	5.6	4.4
Indiana Michigan Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1.8	26.2	27.4
Cost of Purchased Power from Affiliate		223.9	228.6	232.1
Transmission Agreement
Net Charges from Transmission Agreement		103.8	53	38
Central Machine Shop
Billings for Services from Central Machine Shop Facility		2.7	2.9	2.5
Sales and Purchases of Property
Related Party Sales of Property		5	5.2	3
Related Party Purchases of Property		3.5	2.7	8.1
Related Party Transactions (Textuals)
Barge Towing and Chartering Services				19
Indiana Michigan Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0
Indiana Michigan Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate				0
Indiana Michigan Power Co [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	0	0	0
Indiana Michigan Power Co [Member] | Auction Purchases From AEP Energy [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	0	0
Indiana Michigan Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	0	0	0
Indiana Michigan Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		223.9	228.6	232.1
Indiana Michigan Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Indiana Michigan Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		3.8	0
Indiana Michigan Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	0	12	17.1
Indiana Michigan Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Indiana Michigan Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(4.4)	12.2	8.4
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		2.4	2	1.9
Kentucky Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		5	5.3	4.6
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1.8	1.5	1.3
Ohio Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		24.4	17.3	84.1
Cost of Purchased Power from Affiliate		108.5	141.9	527.1
Generation Deferrals		0	(82.7)	(30.7)
Transmission Agreement
Net Charges from Transmission Agreement		248.6	143.6	81
Sales and Purchases of Property
Related Party Sales of Property		2.9	1.9	2.4
Related Party Purchases of Property		1.6	1.7	2.1
Ohio Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0
Ohio Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]			269.2
Ohio Power Co [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	96.5	110.1	225.2
Ohio Power Co [Member] | Auction Purchases From AEP Energy [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	5.5	7.7
Ohio Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	6.5	24.1	32.7
Ohio Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0	0
Ohio Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Ohio Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0
Ohio Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	0	0	0
Ohio Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	29.7
Ohio Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		6.2	(2)	35.5
Ohio Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		18.2	19.3	18.9
Public Service Co Of Oklahoma [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4.3	2.6	4.6
Cost of Purchased Power from Affiliate		0	3.7	0
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		56	19.6	15
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1.1	0.5	0.2
Sales and Purchases of Property
Related Party Sales of Property		1.5	7.5	7.1
Related Party Purchases of Property		0.2	3.2	0.6
Public Service Co Of Oklahoma [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			3.7
Public Service Co Of Oklahoma [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate				0
Public Service Co Of Oklahoma [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	0	0	0
Public Service Co Of Oklahoma [Member] | Auction Purchases From AEP Energy [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	0	0
Public Service Co Of Oklahoma [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	0	0	0
Public Service Co Of Oklahoma [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0	0
Public Service Co Of Oklahoma [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Public Service Co Of Oklahoma [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0
Public Service Co Of Oklahoma [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	0	0	0
Public Service Co Of Oklahoma [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Public Service Co Of Oklahoma [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	(1.7)	0.2
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4.3	4.3	4.4
Southwestern Electric Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		25.9	24.5	16.6
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		6.6	(19.6)	(15)
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0.8	0.9	0.8
Sales and Purchases of Property
Related Party Sales of Property		0.5	1	0.8
Related Party Purchases of Property		0.4	6.5	7.4
Southwestern Electric Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Southwestern Electric Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	3.7
Southwestern Electric Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	0	0	0
Southwestern Electric Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(0.2)	(0.2)	(0.2)
Southwestern Electric Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		24.2	19.4	15.2
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1.9	1.6	1.6
Wheeling Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		5	4.8	0
AEP Texas Inc. [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		65.7	75.7	78.5
ERCOT Transmission Service Charges [Abstract]
Billings from ETT for ERCOT Wholesale Transmission Services		30	29	27
Oklaunion PPA between AEP Texas and AEPEP [Abstract]
Oklaunion Purchase Power Agreement		52	51.5
Sales and Purchases of Property
Related Party Sales of Property		0.2	0.3	0.6
Related Party Purchases of Property		$ 0.4	0.7	0.9
Related Party Transactions (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		54.69%
AEP Texas Inc. [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 0	0	0
AEP Texas Inc. [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0
AEP Texas Inc. [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]	0	0	0
AEP Texas Inc. [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		63.6	73.9	76.9
AEP Texas Inc. [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
AEP Texas Inc. [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 2.1	$ 1.8	$ 1.6
[1]	Refer to the Ohio Auctions section below for further information regarding these amounts.
[2]	Amount excludes $31 million in 2015 which is now presented as Generation Deferrals on the Statement of Income.

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2017USD ($)MW		Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		$ 1,416.5		$ 1,705
Securitized Transition Assets		1,211.2		1,486.1
PATH-WV Refund		$ 11.4
Percentage of Ownership of Allegheny Series by a Nonaffiliated Company		100.00%
AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		$ 1,000		1,200
Securitized Transition Assets		870		1,100
AEP Texas Central Transition Funding Co [Member] | Current Assets [Member]
ASSETS
Assets		191.7		184.8
AEP Texas Central Transition Funding Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
AEP Texas Central Transition Funding Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		923.5	[1]	1,149.4	[2]
AEP Texas Central Transition Funding Co [Member] | Total Assets [Member]
ASSETS
Assets		1,115.2		1,334.2
AEP Texas Central Transition Funding Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		260.9		251.9
AEP Texas Central Transition Funding Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		836.1		1,064.2
AEP Texas Central Transition Funding Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		18.2		18.1
AEP Texas Central Transition Funding Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1,115.2		1,334.2
Protected Cell Of Energy Insurance Services, Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Insurance Premium Expense to Protected Cell		29		28		$ 29
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Assets [Member]
ASSETS
Assets		178.7		170.6
Protected Cell Of Energy Insurance Services, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
Protected Cell Of Energy Insurance Services, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		0		1.1
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Assets [Member]
ASSETS
Assets		178.7		171.7
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		36.4		31.8
Protected Cell Of Energy Insurance Services, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		95.2		97.3
Protected Cell Of Energy Insurance Services, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		47.1		42.6
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		178.7		171.7
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Proceeds from Partnership Contribution		5		45
Transource Energy [Member] | Current Assets [Member]
ASSETS
Assets		17.4		16.3
Transource Energy [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		323.9		313
Transource Energy [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		3.1		5.4
Transource Energy [Member] | Total Assets [Member]
ASSETS
Assets		344.4		334.7
Transource Energy [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		12.4		31.7
Transource Energy [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		132		134.4
Transource Energy [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		200		168.6
Transource Energy [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		344.4		334.7
AEP Renewables [Member]
Variable Interest Entities (Textuals) [Abstract]
Proceeds from Partnership Contribution		$ 140
AEP Renewables [Member] | Current Assets [Member]
ASSETS
Assets				0
AEP Renewables [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets				130.4
AEP Renewables [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets				9
AEP Renewables [Member] | Total Assets [Member]
ASSETS
Assets				139.4
AEP Renewables [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity				126.7
AEP Renewables [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity				11.3
AEP Renewables [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity				1.4
AEP Renewables [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity				139.4
AEP Credit, Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Minimum Percentage of Equity AEP Provides		5.00%
Percentage Of Short Term Borrowing Needs In Excess Of Third Party Financings		20.00%
AEP Credit, Inc. [Member] | Current Assets [Member]
ASSETS
Assets		$ 926.3		945.7
AEP Credit, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
AEP Credit, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		6.4		10.3
AEP Credit, Inc. [Member] | Total Assets [Member]
ASSETS
Assets		932.7		956
AEP Credit, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		872		877.4
AEP Credit, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		0.7		0.6
AEP Credit, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		60		78
AEP Credit, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 932.7		956
PATH West Virginia Transmission Co, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage of Debt Capital Structure in PATH's Stipulation Agreement		50.00%
Percentage of Equity Capital Structure in PATH's Stipulation Agreement		50.00%
Percentage of Cost of Long Term Debt for PATH's Stipulation Agreement		4.70%
Percentage of PATH WV's Lowered Authorized ROE		8.11%
Percentage of PATH WV's Previously Authorized ROE		10.40%
PATH West Virginia Transmission Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		$ 18.8		18.8
Maximum Exposure		18.8		18.8
PATH West Virginia Transmission Co, LLC [Member] | Retained Earnings [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		(2)		(2.3)
Maximum Exposure		(2)		(2.3)
PATH West Virginia Transmission Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		16.8		16.5
Maximum Exposure		$ 16.8		16.5
Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
AEP's Ownership In OVEC		43.47%
Intercompany Power Agreement End Date		2,040
Approximate OVEC Generating Capacity (MWs) | MW		2,400
Outstanding Indebtedness		$ 1,400
Ohio Valley Electric Corporation [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		4.4		4.4
Maximum Exposure		4.4		4.4
Ohio Valley Electric Corporation [Member] | AEP's Ratio of OVEC Debt [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		0		0
Maximum Exposure	[3]	626.3		658.3
Ohio Valley Electric Corporation [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		4.4		4.4
Maximum Exposure		$ 630.7		662.7
Parent Company [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
AEP's Ownership In OVEC		39.17%
Great Plains Energy Inc. [Member] | Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage		13.50%
Cleco Power, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage of VIE Sales of Lignite Produced		50.00%
AEP Transmission Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		$ 188.9		131.1		108.4
AEP Transmission Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		25.1		23
Maximum Exposure		25.1		23
Appalachian Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		295.9		318.9
Securitized Transition Assets		282.3		305.3
Amount Of Power Purchased From O V E C		101		88		87.2
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		268.8		244.2		227.5
Appalachian Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		37		36.7
Maximum Exposure		37		36.7
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		296		319
Securitized Transition Assets		282		305
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Assets [Member]
ASSETS
Assets		22.3		20.2
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		285.6	[4]	309	[5]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation		3.4		3.7
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Assets [Member]
ASSETS
Assets		307.9		329.2
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		27.6		27.3
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		278.4		300.6
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1.9		1.3
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 307.9		329.2
Appalachian Power Co [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Power Participation Ratio		15.69%
Outstanding Indebtedness		$ 226		237.6
Indiana Michigan Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Amount Of Power Purchased From O V E C		$ 50.5		44		43.7
Indiana Michigan Power Co [Member] | Rockport Generating Plant (Unit No. 1) [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Variable Interest Entities (Textuals) [Abstract]
Payments Made by I&M to DCC Fuel		$ 136		101		115
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Assets [Member]
ASSETS
Assets		102.5		135.5
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		179.9		233.9
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		86.3		116.2
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Assets [Member]
ASSETS
Assets		368.7		485.6
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		96.5		131.3
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		272.2		354.3
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		0		0
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		368.7		485.6
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		176		147.7		139.5
Indiana Michigan Power Co [Member] | Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		224		229		232
Indiana Michigan Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		26.8		24.2
Maximum Exposure		26.8		24.2
Indiana Michigan Power Co [Member] | Carrying Amount in AEP Generating Company's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		$ 23		22
Indiana Michigan Power Co [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Power Participation Ratio		7.85%
Outstanding Indebtedness		$ 113.1		118.9
Ohio Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		94.5		140.2
Securitized Transition Assets		37.7		62.1
Amount Of Power Purchased From O V E C		128.2		111.7		110.8
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		195.7		181.1		177.8
Ohio Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		27.4		28.1
Maximum Exposure		27.4		28.1
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		95		140
Securitized Transition Assets		38		62
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Assets [Member]
ASSETS
Assets		28.7		30.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		71	[6]	117.1	[7]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation		33.3		55
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Assets [Member]
ASSETS
Assets		99.7		147.4
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		47.9		47.5
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		50.5		98.6
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1.3		1.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 99.7		147.4
Ohio Power Co [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
AEP's Ownership In OVEC		4.30%
Power Participation Ratio		19.93%
Outstanding Indebtedness		$ 287.2		301.8
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		114.7		111		107.3
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		18.7		16
Maximum Exposure		18.7		16
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		137		162		152
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Assets [Member]
ASSETS
Assets		56.3		60.2
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		113.2		112
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		90.2		89.8
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Assets [Member]
ASSETS
Assets		259.7		262
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		49.1		26.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		211		235.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		(0.4)		0.4
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		259.7		262
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		150.7		147		141.4
Southwestern Electric Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		20.8		21.8
Maximum Exposure		20.8		21.8
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		$ 61		65		93
Percentage of VIE Sales of Lignite Produced		50.00%
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO		50.00%
Percentage of Management Fee Received by SWEPCo from DHLC		100.00%
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		$ 7.6		7.6
Maximum Exposure		7.6		7.6
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Retained Earnings [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		11.8		15.7
Maximum Exposure		11.8		15.7
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | SWEPCo's Share of Obligations [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		0		0
Maximum Exposure		144.3		91.3
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		19.4		23.3
Maximum Exposure		$ 163.7		114.6
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 1) [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
Percentage Interest in Rockport Plant Unit 2 Lease		50.00%
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share		100.00%
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage		86.50%
AEP Texas Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		$ 1,026.1		1,245.8
Securitized Transition Assets		$ 891.2		1,118.7
Jointly Owned Utility Plant, Proportionate Ownership Share		54.69%
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitized Transition Assets		$ 869.5		1,088.3
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Other Noncurrent Assets [Member]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation		53.9		61.1
AEP Texas Inc. [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		152.6		142.3		$ 132.7
AEP Texas Inc. [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet		24.2		22.9
Maximum Exposure		$ 24.2		$ 22.9
[1]	Includes an intercompany item eliminated in consolidation of $53.9 million.
[2]	Includes an intercompany item eliminated in consolidation of $61.1 million.
[3]	Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt is $226 million, $113.1 million and $287.2 million for the year ended December 31, 2017 and $237.6 million, $118.9 million and $301.8 million for the year-ended December 31, 2016, respectively.
[4]	Includes an intercompany item eliminated in consolidation of $3.4 million.
[5]	Includes an intercompany item eliminated in consolidation of $3.7 million.
[6]	Includes an intercompany item eliminated in consolidation of $33.3 million.
[7]	Includes an intercompany item eliminated in consolidation of $55 million.

Property, Plant and Equipment77

Property, Plant and Equipment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)		Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 20,760.5		$ 19,848.9
Property, Plant and Equipment, Transmission	18,972.5		16,658.7
Property, Plant and Equipment, Distribution	19,868.5		18,900.8
Property, Plant and Equipment, Other	3,706.3		3,444.3
Property, Plant and Equipment, Construction Work in Progress	4,120.7		3,183.9
Accumulated Depreciation	17,167		16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	50,261.5		45,639.3	[1]
Asset Retirement Obligations (ARO)
Beginning Balance	1,934.9	[2],[3],[4],[5]	1,916.3	[2],[3],[4],[5]
Accretion Expense	90.9	[2],[3],[4],[5]	91.3	[2],[3],[4],[5]
Liabilities Incurred	2.4	[2],[3],[4],[5]	0.8	[2],[3],[4],[5]
Liabilities Settled	(104.5)	[2],[3],[4],[5]	(139.9)	[2],[3],[4],[5],[6]
Revisions in Cash Flow Estimates	82	[2],[3],[4],[5]	66.4	[2],[3],[4],[5]
Ending Balance	2,005.7	[2],[3],[4],[5]	1,934.9	[2],[3],[4],[5]	$ 1,916.3	[2],[3],[4],[5]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	93.7		113.2		131.9
Allowance for Borrowed Funds Used During Construction	48.6		51.7		61.3
Jointly-owned Electric Facilities
Utility Plant in Service	3,399.3		3,458.2
Construction Work in Progress	31.6		18.8
Accumulated Depreciation	1,169.5		1,110.1
Asset Impairments and Other Related Charges	87.1		2,267.8		0
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant	1,300		1,240
Fair Value of Legally Restricted Assets	2,220		1,950
AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	350.7		349.6
Property, Plant and Equipment, Transmission	3,053.6		2,623.6
Property, Plant and Equipment, Distribution	3,718.6		3,527.2
Property, Plant and Equipment, Other	461		436.4
Property, Plant and Equipment, Construction Work in Progress	835.7		385.9
Accumulated Depreciation	1,594.5		1,542
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,825.1		5,780.7
Asset Retirement Obligations (ARO)
Beginning Balance	25.5	[3],[4]	24	[3],[4]
Accretion Expense	1.2	[3],[4]	1.1	[3],[4]
Liabilities Incurred	0	[3],[4]	0	[3],[4]
Liabilities Settled	(0.1)	[3],[4]	(0.1)	[3],[4]
Revisions in Cash Flow Estimates	0.1	[3],[4]	0.5	[3],[4]
Ending Balance	26.7	[3],[4]	25.5	[3],[4]	24	[3],[4]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	6.8		9.2		6.7
Allowance for Borrowed Funds Used During Construction	$ 6.8		5.9		4.5
Jointly-owned Electric Facilities
Percent of Ownership	54.69%
Asset Impairments and Other Related Charges			72.7		0
AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission	$ 5,336.1		3,973.5
Property, Plant and Equipment, Other	131.4		99.4
Property, Plant and Equipment, Construction Work in Progress	1,312.7		981.3
Accumulated Depreciation	170.4		99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,609.8		4,954.6
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	52.3		52.3		53
Allowance for Borrowed Funds Used During Construction	20.2		15.6		17.7
Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	6,446.9		6,332.8
Property, Plant and Equipment, Transmission	3,019.9		2,796.9
Property, Plant and Equipment, Distribution	3,763.8		3,569.1
Property, Plant and Equipment, Other	427.9		373.5
Property, Plant and Equipment, Construction Work in Progress	483		390.3
Accumulated Depreciation	3,896.4		3,636.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	10,245.1		9,825.8
Asset Retirement Obligations (ARO)
Beginning Balance	127.1	[3],[4]	140.2	[3],[4]
Accretion Expense	7	[3],[4]	7.6	[3],[4]
Liabilities Incurred	0	[3],[4]	0	[3],[4]
Liabilities Settled	(21.7)	[3],[4]	(35.3)	[3],[4]
Revisions in Cash Flow Estimates	12.6	[3],[4]	14.6	[3],[4]
Ending Balance	125	[3],[4]	127.1	[3],[4]	140.2	[3],[4]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	9.2		11.7		13.8
Allowance for Borrowed Funds Used During Construction	5.3		6.3		6.9
Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	4,445.9		4,056.1
Property, Plant and Equipment, Transmission	1,504		1,472.8
Property, Plant and Equipment, Distribution	2,069.3		1,899.3
Property, Plant and Equipment, Other	595.2		550.2
Property, Plant and Equipment, Construction Work in Progress	460.2		654.2
Accumulated Depreciation	3,024.2		3,005.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,050.4		5,627.5
Asset Retirement Obligations (ARO)
Beginning Balance	1,258.1	[3],[4],[5]	1,253.8	[3],[4],[5]
Accretion Expense	55.9	[3],[4],[5]	55.6	[3],[4],[5]
Liabilities Incurred	0	[3],[4],[5]	0	[3],[4],[5]
Liabilities Settled	(0.1)	[3],[4],[5]	(62.6)	[3],[4],[5],[6]
Revisions in Cash Flow Estimates	7.9	[3],[4],[5]	11.3	[3],[4],[5]
Ending Balance	1,321.8	[3],[4],[5]	1,258.1	[3],[4],[5]	1,253.8	[3],[4],[5]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	11.1		15.3		11.6
Allowance for Borrowed Funds Used During Construction	6.7		7.2		5
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges	0		10.5		0
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant	1,300	[5]	1,240	[5]
Fair Value of Legally Restricted Assets	2,220		1,950
Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission	2,419.2		2,319.2
Property, Plant and Equipment, Distribution	4,626.4		4,457.2
Property, Plant and Equipment, Other	495.9		443.7
Property, Plant and Equipment, Construction Work in Progress	410.1		221.5
Accumulated Depreciation	2,184.8		2,116
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	5,766.8		5,325.6
Asset Retirement Obligations (ARO)
Beginning Balance	1.7	[3]	1.4	[3]
Accretion Expense	0.1	[3]	0.1	[3]
Liabilities Incurred	0	[3]	0.2	[3]
Liabilities Settled	(0.1)	[3]	0	[3]
Revisions in Cash Flow Estimates	0	[3]	0	[3]
Ending Balance	1.7	[3]	1.7	[3]	1.4	[3]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	6.4		6		8.8
Allowance for Borrowed Funds Used During Construction	3.8		3.3		4.8
Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	1,577.2		1,559.3
Property, Plant and Equipment, Transmission	858.8		832.8
Property, Plant and Equipment, Distribution	2,445.1		2,322.4
Property, Plant and Equipment, Other	287.4		233.2
Property, Plant and Equipment, Construction Work in Progress	111.3		148.2
Accumulated Depreciation	1,393.6		1,272.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	3,886.2		3,823.2
Asset Retirement Obligations (ARO)
Beginning Balance	53.4	[3],[4]	47.8	[3],[4]
Accretion Expense	3.1	[3],[4]	3	[3],[4]
Liabilities Incurred	0	[3],[4]	0.1	[3],[4]
Liabilities Settled	(0.5)	[3],[4]	(1)	[3],[4]
Revisions in Cash Flow Estimates	(2)	[3],[4]	3.5	[3],[4]
Ending Balance	54	[3],[4]	53.4	[3],[4]	47.8	[3],[4]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	0.5		6.2		8.8
Allowance for Borrowed Funds Used During Construction	1.1		3.4		5
Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	4,624.9		4,607.6
Property, Plant and Equipment, Transmission	1,679.8		1,584.2
Property, Plant and Equipment, Distribution	2,095.8		2,020.6
Property, Plant and Equipment, Other	684.1		670.4
Property, Plant and Equipment, Construction Work in Progress	233.2		113.8
Accumulated Depreciation	2,685.8		2,567.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,632		6,429.5
Asset Retirement Obligations (ARO)
Beginning Balance	156.5	[2],[3],[4]	125.4	[2],[3],[4]
Accretion Expense	8.3	[2],[3],[4]	7	[2],[3],[4]
Liabilities Incurred	0	[2],[3],[4]	0.2	[2],[3],[4]
Liabilities Settled	(0.3)	[2],[3],[4]	(8.3)	[2],[3],[4]
Revisions in Cash Flow Estimates	4.7	[2],[3],[4]	32.2	[2],[3],[4]
Ending Balance	169.2	[2],[3],[4]	156.5	[2],[3],[4]	125.4	[2],[3],[4]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	2.4		11		26.4
Allowance for Borrowed Funds Used During Construction	2.1		6.9		14.8
Jointly-owned Electric Facilities
Utility Plant in Service	2,878.1		2,940.9
Construction Work in Progress	25.2		14.6
Accumulated Depreciation	868.7		819
Asset Impairments and Other Related Charges	$ 33.6		$ 0		$ 0
Conesville Generating Station (Unit No. 4) [Member]
Jointly-owned Electric Facilities
Percent of Ownership	83.50%
Acquired Ownership Interest	40.00%
Conesville Generating Station (Unit No. 4) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	83.50%	[7],[8],[9]	43.50%	[7],[8],[9]
Utility Plant in Service	$ 2.1	[7],[8],[9]	$ 0.1	[7],[8],[9]
Construction Work in Progress	4.2	[7],[8],[9]	1.3	[7],[8],[9]
Accumulated Depreciation	$ 0.1	[7],[8],[9]	$ 0	[7],[8],[9]
J.M. Stuart Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	26.00%	[7],[10]	26.00%	[7],[10]
Utility Plant in Service	$ 0	[7],[10]	$ 0	[7],[10]
Construction Work in Progress	0	[7],[10]	0.8	[7],[10]
Accumulated Depreciation	$ 0	[7],[10]	$ 0	[7],[10]
Wm. H. Zimmer Generating Station [Member]
Jointly-owned Electric Facilities
Percent of Ownership	25.40%
Wm. H. Zimmer Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership			25.40%	[7],[11],[12]
Utility Plant in Service			$ 0	[7],[11],[12]
Construction Work in Progress			0.3	[7],[11],[12]
Accumulated Depreciation			$ 0	[7],[11],[12]
Dolet Hills Generating Station (Unit No. 1) [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	40.20%	[13]	40.20%	[13]
Utility Plant in Service	$ 343.1	[13]	$ 334.8	[13]
Construction Work in Progress	5.3	[13]	5	[13]
Accumulated Depreciation	$ 214.2	[13]	$ 207.5	[13]
Dolet Hills Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	40.20%	[13]	40.20%	[13]
Utility Plant in Service	$ 343.1	[13]	$ 334.8	[13]
Construction Work in Progress	5.3	[13]	5	[13]
Accumulated Depreciation	$ 214.2	[13]	$ 207.5	[13]
Flint Creek Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	50.00%	[14]	50.00%	[14]
Utility Plant in Service	$ 364.8	[14]	$ 362.4	[14]
Construction Work in Progress	8.9	[14]	3.7	[14]
Accumulated Depreciation	$ 81.6	[14]	$ 73.5	[14]
Flint Creek Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	50.00%	[14]	50.00%	[14]
Utility Plant in Service	$ 364.8	[14]	$ 362.4	[14]
Construction Work in Progress	8.9	[14]	3.7	[14]
Accumulated Depreciation	$ 81.6	[14]	$ 73.5	[14]
Pirkey Generating Station (Unit No. 1) [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	85.90%	[14]	85.90%	[14]
Utility Plant in Service	$ 589.8	[14]	$ 586.4	[14]
Construction Work in Progress	7.8	[14]	5.7	[14]
Accumulated Depreciation	$ 406.3	[14]	$ 399.5	[14]
Pirkey Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	85.90%	[14]	85.90%	[14]
Utility Plant in Service	$ 589.8	[14]	$ 586.4	[14]
Construction Work in Progress	7.8	[14]	5.7	[14]
Accumulated Depreciation	$ 406.3	[14]	$ 399.5	[14]
Oklaunion Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	70.30%	[15]	70.30%	[15]
Utility Plant in Service	$ 456.4	[15]	$ 454.8	[15]
Construction Work in Progress	1.9	[15]	1.3	[15]
Accumulated Depreciation	$ 254.6	[15]	$ 246	[15]
Oklaunion Generating Station (Unit No. 1) [Member] | AEP Texas Inc. [Member]
Jointly-owned Electric Facilities
Percent of Ownership	54.70%
Oklaunion Generating Station (Unit No. 1) [Member] | AEP Texas Inc. [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	54.70%	[15]	54.70%	[15]
Utility Plant in Service	$ 350.7	[15]	$ 349.6	[15]
Construction Work in Progress	1.3	[15]	0.9	[15]
Accumulated Depreciation	$ 194.1	[15]	$ 186.5	[15]
Oklaunion Generating Station (Unit No. 1) [Member] | Public Service Co Of Oklahoma [Member]
Jointly-owned Electric Facilities
Percent of Ownership	15.60%
Oklaunion Generating Station (Unit No. 1) [Member] | Public Service Co Of Oklahoma [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	15.60%	[15]	15.60%	[15]
Utility Plant in Service	$ 105.7	[15]	$ 105.2	[15]
Construction Work in Progress	0.6	[15]	0.5	[15]
Accumulated Depreciation	$ 60.5	[15]	$ 59.4	[15]
Turk Generating Plant [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	73.30%	[14],[16]	73.30%	[14]
Utility Plant in Service	$ 1,580.4	[14],[16]	$ 1,657.3	[14]
Construction Work in Progress	3.2	[14],[16]	0.2	[14]
Accumulated Depreciation	166.6	[14],[16]	$ 138.5	[14]
Turk Generating Plant [Member] | Southwestern Electric Power Co [Member]
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges	$ 15
Turk Generating Plant [Member] | Southwestern Electric Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	73.30%	[14],[16]	73.30%	[14]
Utility Plant in Service	$ 1,580.4	[14],[16]	$ 1,657.3	[14]
Construction Work in Progress	3.2	[14],[16]	0.2	[14]
Accumulated Depreciation	$ 166.6	[14],[16]	$ 138.5	[14]
Jointly Owned Electricity Transmission and Distribution System [Member]
Jointly-owned Electric Facilities
Percent of Ownership		[17]		[17]
Utility Plant in Service	$ 62.7		$ 62.4
Construction Work in Progress	0.3		0.5
Accumulated Depreciation	$ 46.1		$ 45.1
Rockport Generating Plant (Unit No. 1) [Member] | Indiana Michigan Power Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership	50.00%
Rockport Generating Plant (Unit No. 1) [Member] | Indiana Michigan Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	50.00%	[18],[19],[20]	50.00%	[18],[19],[20]
Utility Plant in Service	$ 1,093.9	[18],[19],[20]	$ 936.1	[18],[19],[20]
Construction Work in Progress	28.2	[18],[19],[20]	125.8	[18],[19],[20]
Accumulated Depreciation	$ 562.6	[18],[19],[20]	535.1	[18],[19],[20]
Rockport Generating Plant (Unit No. 1) [Member] | AEP Generating Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership	50.00%
Rockport Generating Plant (Unit No. 2) [Member] | AEP Generating Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership	50.00%
Regulated Operation [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 20,406.5	[21]	19,703.9	[21]
Property, Plant and Equipment, Transmission	18,942.3		16,658.6
Property, Plant and Equipment, Distribution	19,865.9		18,898.2
Property, Plant and Equipment, Other	3,224.8		2,902
Property, Plant and Equipment, Construction Work in Progress	3,972.6	[21]	3,072.2	[21]
Accumulated Depreciation	16,906.7		16,101.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 49,505.4		$ 45,133.4
Regulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	132 years		132 years		132 years
Depreciable Life Ranges - Transmission	100 years		100 years		81 years
Depreciable Life Ranges - Distribution	156 years		156 years		75 years
Depreciable Life Ranges - Other	84 years		84 years		75 years
Regulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	20 years		35 years		35 years
Depreciable Life Ranges - Transmission	15 years		15 years		15 years
Depreciable Life Ranges - Distribution	5 years		7 years		7 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.70%		4.00%		3.10%
Regulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.10%		0.40%
Regulated Operation [Member] | Transmission [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.70%		2.70%
Regulated Operation [Member] | Transmission [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	1.60%		1.50%		1.40%
Regulated Operation [Member] | Distribution [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.70%		3.70%		3.70%
Regulated Operation [Member] | Distribution [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.60%		2.50%
Regulated Operation [Member] | Other Property Class [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	9.20%		8.60%		11.80%
Regulated Operation [Member] | Other Property Class [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		3.10%		2.90%
Regulated Operation [Member] | AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 0		$ 0
Property, Plant and Equipment, Transmission	3,053.6		2,623.6
Property, Plant and Equipment, Distribution	3,718.6		3,527.2
Property, Plant and Equipment, Other	457.6		432.1
Property, Plant and Equipment, Construction Work in Progress	834.4		385
Accumulated Depreciation	1,399.4		1,354.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,664.8		$ 5,613.5
Regulated Operation [Member] | AEP Texas Inc. [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	81 years		81 years		81 years
Depreciable Life Ranges - Distribution	70 years		70 years		70 years
Depreciable Life Ranges - Other	50 years		50 years		50 years
Regulated Operation [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	45 years		45 years		45 years
Depreciable Life Ranges - Distribution	7 years		7 years		7 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | AEP Texas Inc. [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	1.70%		1.80%		1.80%
Regulated Operation [Member] | AEP Texas Inc. [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.60%		3.30%		3.30%
Regulated Operation [Member] | AEP Texas Inc. [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	8.70%		8.30%		9.70%
Regulated Operation [Member] | AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 0		$ 0
Property, Plant and Equipment, Transmission	5,336.1		3,973.5
Property, Plant and Equipment, Distribution	0		0
Property, Plant and Equipment, Other	130		98.3
Property, Plant and Equipment, Construction Work in Progress	1,312.7		981.3
Accumulated Depreciation	170.4		99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,608.4		$ 4,953.5
Regulated Operation [Member] | AEP Transmission Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	100 years		100 years		75 years
Regulated Operation [Member] | AEP Transmission Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	20 years		20 years		20 years
Regulated Operation [Member] | AEP Transmission Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	1.70%		1.60%		1.40%
Regulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 6,446.9		$ 6,332.8
Property, Plant and Equipment, Transmission	3,019.9		2,796.9
Property, Plant and Equipment, Distribution	3,763.8		3,569.1
Property, Plant and Equipment, Other	399.5		345.1
Property, Plant and Equipment, Construction Work in Progress	483		390.3
Accumulated Depreciation	3,891.1		3,631.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 10,222		$ 9,802.7
Regulated Operation [Member] | Appalachian Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	112 years		121 years		121 years
Depreciable Life Ranges - Transmission	68 years		68 years		68 years
Depreciable Life Ranges - Distribution	57 years		57 years		57 years
Depreciable Life Ranges - Other	55 years		55 years		55 years
Regulated Operation [Member] | Appalachian Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	35 years		35 years		35 years
Depreciable Life Ranges - Transmission	15 years		15 years		15 years
Depreciable Life Ranges - Distribution	10 years		10 years		10 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | Appalachian Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.10%		3.10%		3.10%
Regulated Operation [Member] | Appalachian Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	1.60%		1.50%		1.60%
Regulated Operation [Member] | Appalachian Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.70%		3.70%		3.60%
Regulated Operation [Member] | Appalachian Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	6.50%		6.00%		8.30%
Regulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 4,445.9		$ 4,056.1
Property, Plant and Equipment, Transmission	1,504		1,472.8
Property, Plant and Equipment, Distribution	2,069.3		1,899.3
Property, Plant and Equipment, Other	552.3		507.7
Property, Plant and Equipment, Construction Work in Progress	460.2		654.2
Accumulated Depreciation	3,011.7		2,989.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,020		$ 5,600.2
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	132 years		132 years		132 years
Depreciable Life Ranges - Transmission	75 years		75 years		75 years
Depreciable Life Ranges - Distribution	70 years		70 years		70 years
Depreciable Life Ranges - Other	45 years		45 years		45 years
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	20 years		59 years		59 years
Depreciable Life Ranges - Transmission	50 years		50 years		50 years
Depreciable Life Ranges - Distribution	10 years		10 years		10 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.40%		2.40%		2.50%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	1.70%		1.70%		1.70%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.80%		2.80%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	8.40%		8.60%		11.80%
Regulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 0		$ 0
Property, Plant and Equipment, Transmission	2,419.2		2,319.2
Property, Plant and Equipment, Distribution	4,626.4		4,457.2
Property, Plant and Equipment, Other	485.5		433.4
Property, Plant and Equipment, Construction Work in Progress	410.1		221.5
Accumulated Depreciation	2,183.9		2,115.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 5,757.3		$ 5,316.2
Regulated Operation [Member] | Ohio Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	60 years		60 years		60 years
Depreciable Life Ranges - Distribution	57 years		57 years		57 years
Depreciable Life Ranges - Other	50 years		50 years		50 years
Regulated Operation [Member] | Ohio Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	39 years		39 years		39 years
Depreciable Life Ranges - Distribution	5 years		7 years		7 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | Ohio Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.30%		2.30%
Regulated Operation [Member] | Ohio Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.80%		2.80%		2.80%
Regulated Operation [Member] | Ohio Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	6.20%		5.90%		7.20%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 1,577.2		$ 1,559.3
Property, Plant and Equipment, Transmission	858.8		832.8
Property, Plant and Equipment, Distribution	2,445.1		2,322.4
Property, Plant and Equipment, Other	282		227.3
Property, Plant and Equipment, Construction Work in Progress	111.3		148.2
Accumulated Depreciation	1,393.6		1,272.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 3,880.8		$ 3,817.3
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	85 years		85 years		70 years
Depreciable Life Ranges - Transmission	100 years		100 years		75 years
Depreciable Life Ranges - Distribution	156 years		156 years		65 years
Depreciable Life Ranges - Other	84 years		84 years		40 years
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	35 years		35 years		35 years
Depreciable Life Ranges - Transmission	45 years		45 years		40 years
Depreciable Life Ranges - Distribution	27 years		27 years		7 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.40%		2.40%		1.70%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.20%		2.20%		1.90%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.70%		2.50%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	7.40%		6.40%		4.60%
Regulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 4,624.9	[21]	$ 4,607.6	[21]
Property, Plant and Equipment, Transmission	1,679.8		1,584.2
Property, Plant and Equipment, Distribution	2,095.8		2,020.6
Property, Plant and Equipment, Other	416.8		399.3
Property, Plant and Equipment, Construction Work in Progress	220.7	[21]	113.7	[21]
Accumulated Depreciation	2,520.5		2,411.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,517.5		$ 6,313.9
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	70 years		70 years		70 years
Depreciable Life Ranges - Transmission	73 years		70 years		70 years
Depreciable Life Ranges - Distribution	70 years		65 years		65 years
Depreciable Life Ranges - Other	55 years		51 years		51 years
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	40 years		40 years		40 years
Depreciable Life Ranges - Transmission	50 years		50 years		50 years
Depreciable Life Ranges - Distribution	25 years		25 years		25 years
Depreciable Life Ranges - Other	5 years		5 years		5 years
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.10%		2.20%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.20%		2.30%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.60%		2.60%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	7.20%		6.80%		5.50%
Unregulated Operation [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 756.1		$ 505.9
Unregulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	66 years		66 years		66 years
Depreciable Life Ranges - Transmission	40 years		55 years		55 years
Depreciable Life Ranges - Distribution	40 years		50 years		0 years
Depreciable Life Ranges - Other	50 years	[22]	50 years	[22]	50 years	[22]
Unregulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	15 years		40 years		35 years
Depreciable Life Ranges - Transmission			43 years		43 years
Depreciable Life Ranges - Distribution			40 years		0 years
Depreciable Life Ranges - Other	5 years	[22]	5 years	[22]	5 years	[22]
Unregulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	5.10%		17.20%		3.40%
Unregulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.40%		2.80%		2.50%
Unregulated Operation [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	0.20%		2.30%		2.30%
Unregulated Operation [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		1.30%		0.00%
Unregulated Operation [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	12.10%		9.10%		2.70%
Unregulated Operation [Member] | AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 160.3		$ 167.2
Unregulated Operation [Member] | AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	1.4		1.1
Unregulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	23.1		23.1
Unregulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	30.4		27.3
Unregulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	9.5		9.4
Unregulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	5.4		5.9
Unregulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 114.5		115.6
Unregulated Operation [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Other	20 years
Unregulated Operation [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Other	3 years
Tanners Creek Plant Units 1 Through 4 [Member]
Asset Retirement Obligations (ARO)
Liabilities Settled			61
Tanners Creek Plant Units 1 Through 4 [Member] | Indiana Michigan Power Co [Member]
Asset Retirement Obligations (ARO)
Liabilities Settled			61
Generation and Marketing [Member]
Depreciation, Depletion and Amortization
Accumulated Depreciation	$ 75		42.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	569.6		322.5
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges	$ 53.5		2,257.3
Property, Plant and Equipment (Textuals) [Abstract]
Property, Plant and Equipment -Assets Held for Sale			$ 1,756.2
[1]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[2]	Includes ARO related to Sabine and DHLC.
[3]	Includes ARO related to asbestos removal.
[4]	Includes ARO related to ash disposal facilities.
[5]	Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.30 billion and $1.24 billion as of December 31, 2017 and 2016, respectively.
[6]	Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7.
[7]	Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. J.M. Stuart Generating Station and Wm. H. Zimmer Generating Station were impaired as of November 30, 2016. See the “Impairments” section of Note 7.
[8]	In accordance with the Asset Purchase Agreement between AGR and Dynegy Corporation dated February 2017, AGR acquired Dynegy Corporation’s 40% ownership interest in Conesville Generating Station, Unit 4. Subsequent to this transaction, AGR’s ownership percentage in Conesville Generating Station, Unit 4 is 83.5%.
[9]	Operated by AGR.
[10]	Operated by Dayton Power & Light Company, a non-affiliated company.
[11]	In accordance with the Asset Purchase Agreement between AGR and Dynegy Corporation dated February 2017, Dynegy Corporation acquired AGR’s 25.4% ownership interest in Wm. H. Zimmer Generating Station. Subsequent to this transaction, AGR has no ownership interest in Wm. H. Zimmer Generating Station. See the “Dispositions” section of Note 7.
[12]	Operated by Dynegy Corporation, a non-affiliated company.
[13]	Operated by CLECO, a non-affiliated company.
[14]	Operated by SWEPCo.
[15]	Operated by PSO, which owns 15.6%. Also jointly-owned (54.7%) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7.
[16]	In December 2017, SWEPCo recorded a $15 million pretax impairment related to the Louisiana jurisdictional share of Turk Plant. Amount reflects the impact of the impairment. See the “Impairments” section of Note 7.
[17]	Varying percentages of ownership.
[18]	AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.
[19]	Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13.
[20]	Operated by I&M.
[21]	AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
[22]	SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

Unaudited Quarterly Financial78

Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 3,810.4		$ 4,104.7		$ 3,576.5		$ 3,933.3		$ 3,790.1		$ 4,652.2		$ 3,892.9		$ 4,044.9		$ 15,424.9	$ 16,380.1	$ 16,453.2
Operating Income (Loss)	742.2		986.5		744.7		1,097.1		575.9		(1,127.9)	[1]	866.2		892.9		3,570.5	1,207.1	3,333.5
Income (Loss) from Continuing Operations									375.2		(764.2)	[1]	506.4		503.1		1,928.9	620.5	1,768.6
Income (Loss) from Discontinued Operations, Net of Tax									0		0		(2.5)	[2]	0		0	(2.5)	283.7
Net Income (Loss)	401.8		556.7		376.2		594.2		375.2		(764.2)	[1]	503.9		503.1		1,928.9	618	2,052.3
Amounts Attributable to Common Shareholders
Earnings (Loss) Attributable To Common Shareholders	$ 400.7		$ 544.7		$ 375		$ 592.2		$ 373.4		$ (765.8)	[3]	$ 502.1		$ 501.2		$ 1,912.6	$ 610.9	$ 2,047.1
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 0.81	[4]	$ 1.11	[4]	$ 0.76	[4]	$ 1.20	[4]	$ 0.76	[4]	$ (1.56)	[3],[4]	$ 1.03	[4]	$ 1.02	[4]	$ 3.89	$ 1.25	$ 3.59
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations									0	[5]	0	[5]	(0.01)	[5]	0	[5]	0	(0.01)	0.58
Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders									0.76	[4]	(1.56)	[3],[4]	1.02	[4]	1.02	[4]	3.89	1.24	4.17
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 0.81	[4]	$ 1.10	[4]	$ 0.76	[4]	$ 1.20	[4]	0.76	[4]	(1.56)	[3],[4]	1.03	[4]	1.02	[4]	3.88	1.25	3.59
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations									0	[5]	0	[5]	(0.01)	[5]	0	[5]	0	(0.01)	0.58
Total Diluted Earnings (Loss) Per Share Attributable to AEP Common Shareholders									$ 0.76	[4]	$ (1.56)	[3],[4]	$ 1.02	[4]	$ 1.02	[4]	$ 3.88	$ 1.24	$ 4.17
AEP Texas Inc. [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 374.1		$ 431.2		$ 389.5		$ 343.6		$ 362		$ 403.9		$ 365		$ 330.5		$ 1,538.4	$ 1,461.4	$ 1,458
Operating Income (Loss)	97.1		129.7		109.7		83.2		81.4		112.4		103.4		82.4		419.7	379.6	320.8
Income (Loss) from Continuing Operations									55.2		55.5		49.7		35		310.5	195.4	121.7
Income (Loss) from Discontinued Operations, Net of Tax									0.6	[6]	(47.4)	[6]	(0.7)	[6]	(1.3)	[6]	0	(48.8)	(1.4)
Net Income (Loss)	163.9		64.3		49		33.3		55.8		8.1		49		33.7		310.5	146.6	120.3
AEP Transmission Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	173.8		167.3		229.4		152.7		120		125.3		153.1		79.6		723.2	478	310.2
Operating Income (Loss)	96.9		95.1		165.4		90.4		60.8		76.4		108.1		34.8		447.8	280.1	174.4
Income (Loss) from Continuing Operations									0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax									0		0		0		0
Net Income (Loss)	61.8		59.9		107.4		57		39.7		52.4		74.8		25.8		286.1	192.7	132.9
Appalachian Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	746.8		719.3		675.3		792.8		729.5		778.2		673.5		820		2,934.2	3,001.2	2,963.5
Operating Income (Loss)	174.9		173		127.4		220.2		136.2		204.4		158.3		244.4		695.5	743.3	710.8
Income (Loss) from Continuing Operations									0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax									0		0		0		0
Net Income (Loss)	82.6		86		52.1		110.6		65.3		104.1		73.4		126.3		331.3	369.1	340.6
Indiana Michigan Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	535.7		557.7		467.3		560.5		514.9		597.6		522.4		532.7		2,121.2	2,167.6	2,186.2
Operating Income (Loss)	84.3		115.1		35.2		118.7		39.6		131.4		94.8		115.8		353.3	381.6	369.9
Income (Loss) from Continuing Operations									0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax									0		0		0		0
Net Income (Loss)	42.9		64.9		10.5		68.4		38.5		75.4		51.3		74.7		186.7	239.9	204.8
Ohio Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	731.9		742		663.9		746.1		588.2		871.3		730.8		763.6		2,883.9	2,953.9	3,148.7
Operating Income (Loss)	145.4		154.5		119.6		150.7		64.3		171.6		138.6		134		570.2	508.5	460.8
Income (Loss) from Continuing Operations									0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax									0		0		0		0
Net Income (Loss)	92.8		82.6		62.3		86.2		37.5		99.9		74.6		70.2		323.9	282.2	232.7
Public Service Co Of Oklahoma [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	335.6		442.8		344.7		304.1		273.6		401.7		300.2		274.3		1,427.2	1,249.8	1,339.2
Operating Income (Loss)	21.2		86.8		46.1		20.8		5.5		98.4		59		35.8		174.9	198.7	193.2
Income (Loss) from Continuing Operations									0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax									0		0		0		0
Net Income (Loss)	0.6		46.2		20.4		4.8		2.6		52.8		28.9		15.7		72	100	92.5
Southwestern Electric Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	436.3		517.6		424.7		401.3		402.3		539.7		427		379		1,779.9	1,748	1,780.9
Operating Income (Loss)	42		137		75		53.7		36.4		147.4		85.9		51.4		307.7	321.1	369.2
Income (Loss) from Continuing Operations									0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax									0		0		0		0
Net Income (Loss)	11		84.1		25.1		17.3		$ 16.5		$ 84.4		$ 44.3		$ 24.5		137.5	169.7	196
Amounts Attributable to Common Shareholders
Earnings (Loss) Attributable To Common Shareholders	$ 10.8		$ 73.1		$ 24.5		$ 16.3										$ 124.7	$ 165.6	$ 192.3
[1]	Includes impairments for certain merchant generation assets (see Note 7).
[2]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[3]	Relates to impairments for certain merchant generation assets (see Note 7).
[4]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[5]	Relates to final accounting adjustment for sale of AEPRO (see Note 7).
[6]	Includes the transfer of the Wind Farms (see Note 7).

Goodwill and Other Intangible79

Goodwill and Other Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in Carrying Amount of Goodwill
Goodwill	$ 52.5	$ 52.5	$ 52.5
Impairment Losses	0	0
Goodwill and Other Intangible Assets (Textuals) [Abstract]
Amortization of Intangible Assets		$ 2	3
Acquired Customer Contracts [Member]
Amortization Life, Gross Carrying Amount and Accumulated Amortization by Major Asset Class
Amortization Life		5 years
Gross Carrying Amount		$ 58.3
Accumulated Amortization		58.3
Corporate and Other [Member]
Changes in Carrying Amount of Goodwill
Goodwill	37.1	37.1	37.1
Impairment Losses	0	0
Generation and Marketing [Member]
Changes in Carrying Amount of Goodwill
Goodwill	15.4	15.4	$ 15.4
Impairment Losses	$ 0	$ 0