Appalachian Power 10-K 21 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2018USD ($)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, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
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 Shell Company	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Filer Category	Large Accelerated Filer
Entity Public Float | $	$ 34,157,276,913
Entity Common Stock, Shares Outstanding	493,245,876
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, 2018	Dec. 31, 2017		Dec. 31, 2016
Revenues
Revenue from Contracts with Customers		$ 16,195.7	$ 15,424.9		$ 16,380.1
Sales to AEP Affiliates		0	0		0
TOTAL REVENUES		16,195.7	15,424.9		16,380.1
Expenses
Other Operation		2,979.2	2,525.2		2,996.1
Maintenance		1,247.4	1,145.6		1,241.7
Asset Impairments and Other Related Charges		70.6	87.1		2,267.8
Gain on Sale of Merchant Generation Assets		0	(226.4)		0
Depreciation and Amortization		2,286.6	1,997.2		1,962.3
Taxes Other Than Income Taxes		1,142.7	1,059.4		1,018
TOTAL EXPENSES		13,513	11,899.9		15,216.2
OPERATING INCOME (LOSS)		2,682.7	3,525		1,163.9
Other Income (Expense):
Interest and Investment Income		11.6	16		16.3
Carrying Costs Income		6.6	18.6		16.2
Allowance for Equity Funds Used During Construction		132.5	93.7		113.2
Non-Service Cost Components of Net Periodic Benefit Cost		124.5	45.5		43.2
Gain on Sale of Equity Investment		0	12.4		0
Interest Expense		(984.4)	(895)		(877.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		1,973.5	2,816.2		475.6
Income Tax Expense (Benefit)		115.3	969.7		(73.7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries		73.1	82.4		71.2
Income (Loss) from Continuing Operations		1,931.3	1,928.9		620.5
Income (Loss) from Discontinued Operations, Net of Tax		0	0		(2.5)
NET INCOME (LOSS)		1,931.3	1,928.9		618
Net Income Attributable to Noncontrolling Interests		7.5	16.3		7.1
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 1,923.8	$ 1,912.6		$ 610.9
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		492,774,600	491,814,651		491,495,458
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS		$ 3.90	$ 3.89		$ 1.25
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS		0	0		(0.01)
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$ 3.90	$ 3.89		$ 1.24
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		493,758,277	492,611,067		491,662,007
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS		$ 3.90	$ 3.88		$ 1.25
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS		0	0		(0.01)
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$ 3.90	$ 3.88		$ 1.24
Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		$ 9,556.7	$ 9,095.1		$ 9,012.4
Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers		4,552.3	4,328.9		4,328.3
Generation and Marketing Revenues [Member]
Revenues
Revenue from Contracts with Customers		1,818.1	1,771.4		2,858.7
Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		268.6	229.5		180.7
TOTAL REVENUES	[1]	123
Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold		2,359.4	2,346.5		2,908.9
Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		3,427.1	2,965.3		2,821.4
AEP Texas Inc. [Member]
Revenues
Revenue from Contracts with Customers		1,493
Sales to AEP Affiliates		105.2	65.7		75.7
TOTAL REVENUES		1,595.3	1,538.4		1,461.4
Expenses
Other Operation		488.9	453.1		457.8
Maintenance		89.4	75.9		73.7
Asset Impairments and Other Related Charges					72.7
Depreciation and Amortization		499.6	450.1		413.9
Taxes Other Than Income Taxes		132.6	122.3		107.6
TOTAL EXPENSES		1,249	1,122.3		1,085.1
OPERATING INCOME (LOSS)		346.3	416.1		376.3
Other Income (Expense):
Interest Income		0.8	2.9		10.9
Allowance for Equity Funds Used During Construction		20	6.8		9.2
Non-Service Cost Components of Net Periodic Benefit Cost		12.3	3.6		3.3
Interest Expense		(147.3)	(142.3)		(144.4)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		232.1	287.1		255.3
Income Tax Expense (Benefit)		20.8	(23.4)		59.9
Income (Loss) from Continuing Operations		211.3	310.5		195.4
Income (Loss) from Discontinued Operations, Net of Tax		0	0		(48.8)
NET INCOME (LOSS)		211.3	310.5		146.6
AEP Texas Inc. [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers		1,486.3	1,470.3		1,383.2
AEP Texas Inc. [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		3.8	2.4		2.5
TOTAL REVENUES	[2]	103.6
AEP Texas Inc. [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold		38.5	20.9		32.1
AEP Transmission Co [Member]
Revenues
Revenue from Contracts with Customers		832
Sales to AEP Affiliates		598.9	568.1	[3]	367.5
TOTAL REVENUES		776.1	706.9	[3]	478
Expenses
Other Operation		83.8	60.1		37
Maintenance		10.5	8.5		6.7
Depreciation and Amortization		133.9	95.7	[3],[4]	65.9
Taxes Other Than Income Taxes		137.8	109.7		88.3
TOTAL EXPENSES		366	274		197.9
OPERATING INCOME (LOSS)		410.1	432.9		280.1
Other Income (Expense):
Interest Income		2.5	1.2	[3]	0.4
Allowance for Equity Funds Used During Construction		70.6	49	[3],[5]	52.3
Interest Expense		(83.2)	(70.2)	[3]	(46)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		400	412.9		286.8
Income Tax Expense (Benefit)		84.1	142.2	[3],[6]	94.1
NET INCOME (LOSS)		315.9	270.7	[3],[6]	192.7
AEP Transmission Co [Member] | Transmission [Member]
Revenues
Revenue from Contracts with Customers		177	138	[3]	110.4
AEP Transmission Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		0.2	0.8	[3]	0.1
TOTAL REVENUES	[2]	0
Appalachian Power Co [Member]
Revenues
Revenue from Contracts with Customers		2,993.2
Sales to AEP Affiliates		181.4	172		142.1
TOTAL REVENUES		2,967.5	2,934.2		3,001.2
Expenses
Other Operation		511.6	503.1		491.7
Maintenance		316.9	251.6		275
Depreciation and Amortization		428.4	407.9		388.5
Taxes Other Than Income Taxes		134.7	126.4		123.5
TOTAL EXPENSES		2,484	2,243.9		2,262.9
OPERATING INCOME (LOSS)		483.5	690.3		738.3
Other Income (Expense):
Interest Income		1.8	1.4		1.3
Carrying Costs Income		1.3	1.4		0.4
Allowance for Equity Funds Used During Construction		13.2	9.2		11.7
Non-Service Cost Components of Net Periodic Benefit Cost		17.9	5.2		5
Interest Expense		(194.8)	(190.9)		(188.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		322.9	516.6		568.2
Income Tax Expense (Benefit)		(44.9)	185.3		199.1
NET INCOME (LOSS)		367.8	331.3		369.1
Appalachian Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		2,777.1	2,749		2,847.4
Appalachian Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		9	13.2		11.7
TOTAL REVENUES	[2]	(1.9)
Appalachian Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold		588.9	597.3		654.9
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		503.5	357.6		329.3
Indiana Michigan Power Co [Member]
Revenues
Revenue from Contracts with Customers		2,381
Sales to AEP Affiliates		22.1	1.8		26.2
Other Revenues - Affiliated		63.4	62.6		62.1
TOTAL REVENUES		2,370.7	2,121.2		2,167.6
Expenses
Purchased Electricity from AEP Affiliates		237.9	223.9		228.6
Other Operation		585.4	591.3		579.3
Maintenance		238.1	208.4		205.6
Asset Impairments and Other Related Charges		0	0		10.5
Depreciation and Amortization		293.1	210.9		191.7
Taxes Other Than Income Taxes		98.9	92.2		94.8
TOTAL EXPENSES		1,993.5	1,774		1,793.3
OPERATING INCOME (LOSS)		377.2	347.2		374.3
Other Income (Expense):
Interest Income		3.4	1.8		1.2
Carrying Costs Income		3.9	12.7		10.1
Allowance for Equity Funds Used During Construction		11.9	11.1		15.3
Non-Service Cost Components of Net Periodic Benefit Cost		18.1	6.1		7.3
Interest Expense		(124.1)	(110.8)		(100.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		290.4	268.1		307.4
Income Tax Expense (Benefit)		29.1	81.4		67.5
NET INCOME (LOSS)		261.3	186.7		239.9
Indiana Michigan Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		2,272.6	2,042.5		2,062.3
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		12.6	14.3		17
Sales to AEP Affiliates		70
TOTAL REVENUES	[2]	(8.2)
Indiana Michigan Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold		318.3	295.1		284.1
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		221.8	152.2		198.7
Ohio Power Co [Member]
Revenues
Revenue from Contracts with Customers		3,079.9
Sales to AEP Affiliates		21	24.4		17.3
TOTAL REVENUES		3,063.4	2,883.9		2,953.9
Expenses
Purchased Electricity from AEP Affiliates		135.3	108.5		141.9
Generation Deferrals		0	0		(82.7)
Amortization of Generation Deferrals		223.9	229.2		242.9
Other Operation		771.3	516		711.2
Maintenance		156	141.2		148
Depreciation and Amortization		259.7	225.9		238.6
Taxes Other Than Income Taxes		412.8	391.5		386.8
TOTAL EXPENSES		2,643.6	2,318.2		2,449.8
OPERATING INCOME (LOSS)		419.8	565.7		504.1
Other Income (Expense):
Interest Income		3.4	4.9		3.8
Carrying Costs Income		1.7	3.6		19.9
Allowance for Equity Funds Used During Construction		9.8	6.4		6
Non-Service Cost Components of Net Periodic Benefit Cost		15.5	4.5		4.4
Interest Expense		(100.7)	(101.9)		(112.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		349.5	483.2		426
Income Tax Expense (Benefit)		24	159.3		143.8
NET INCOME (LOSS)		325.5	323.9		282.2
Ohio Power Co [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers		3,033.8	2,853.5		2,930.1
Ohio Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		8.6	6		6.5
TOTAL REVENUES	[2]	4.3
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		684.6	705.9		663.1
Public Service Co Of Oklahoma [Member]
Revenues
Revenue from Contracts with Customers		1,536.4
Sales to AEP Affiliates		5.4	4.3		2.6
TOTAL REVENUES		1,547.3	1,427.2		1,249.8
Expenses
Purchased Electricity from AEP Affiliates		0	0		3.7
Other Operation		372.8	315.1		291.6
Maintenance		104.8	120.3		106.9
Depreciation and Amortization		164	130.4		130.2
Taxes Other Than Income Taxes		42.8	40.5		35.8
TOTAL EXPENSES		1,404.8	1,255.7		1,054.2
OPERATING INCOME (LOSS)		142.5	171.5		195.6
Other Income (Expense):
Interest Income		0.1	0.1		0.7
Allowance for Equity Funds Used During Construction		0.4	0.5		6.2
Non-Service Cost Components of Net Periodic Benefit Cost		8.7	3.4		3.1
Interest Expense		(63.5)	(53.4)		(51.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		88.2	122.1		154.4
Income Tax Expense (Benefit)		5	50.1		54.4
NET INCOME (LOSS)		83.2	72		100
Public Service Co Of Oklahoma [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		1,537.6	1,417.5		1,242.8
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		4.3	5.4		4.4
TOTAL REVENUES	[2]	0
Public Service Co Of Oklahoma [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold		240.5	134.5		44.8
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		479.9	514.9		441.2
Southwestern Electric Power Co [Member]
Revenues
Revenue from Contracts with Customers		1,817
Sales to AEP Affiliates		28.4	25.9		24.5
TOTAL REVENUES		1,821.9	1,779.9		1,748
Expenses
Other Operation		384.2	318.3		335.4
Maintenance		141.5	143.5		149.7
Asset Impairments and Other Related Charges		0	33.6		0
Depreciation and Amortization		239.5	217.4		196.5
Taxes Other Than Income Taxes		99.6	98.3		88.8
TOTAL EXPENSES		1,544.2	1,475.9		1,430.6
OPERATING INCOME (LOSS)		277.7	304		317.4
Other Income (Expense):
Interest Income		5.4	2.7		1.5
Allowance for Equity Funds Used During Construction		6	2.4		11
Non-Service Cost Components of Net Periodic Benefit Cost		8.7	3.7		3.7
Interest Expense		(127.9)	(123.4)		(119.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		169.9	189.4		213.9
Income Tax Expense (Benefit)		20.4	48.1		52.1
Equity Earnings (Loss) of Unconsolidated Subsidiaries		2.7	(3.8)		7.9
NET INCOME (LOSS)		152.2	137.5		169.7
Net Income Attributable to Noncontrolling Interests		5	12.8		4.1
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS		147.2	124.7		165.6
Southwestern Electric Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		1,791.9	1,752.1		1,721.5
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		1.6	1.9		2
TOTAL REVENUES	[2]	0
Southwestern Electric Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold		502.3	496.1		517.8
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		$ 177.1	$ 168.7		$ 142.4
[1]	Amounts include affiliated and nonaffiliated revenues.
[2]	Amounts include affiliated and nonaffiliated revenues.
[3]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[4]	(a)Reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see “Revisions to Previously Issued Financial Statements” below.
[5]	The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[6]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Net Income (Loss)	$ 1,931.3	$ 1,928.9		$ 618
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	14.6	(2.6)		(16.4)
Securities Available for Sale, Net of Tax	0	3.5		1.3
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(5.3)	1.1		0.6
Pension and OPEB Funded Status, Net of Tax	(33)	86.5		(14.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(23.7)	88.5		(29.2)
TOTAL COMPREHENSIVE INCOME (LOSS)	1,907.6	2,017.4		588.8
Total Comprehensive Income Attributable to Noncontrolling Interest	7.5	16.3		7.1
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	1,900.1	2,001.1		581.7
AEP Texas Inc. [Member]
Net Income (Loss)	211.3	310.5		146.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1	0.9		1.1
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.2	0.3		0.3
Pension and OPEB Funded Status, Net of Tax	(1)	1.1		0.9
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.2	2.3		2.3
TOTAL COMPREHENSIVE INCOME (LOSS)	211.5	312.8		148.9
AEP Transmission Co [Member]
Net Income (Loss)	315.9	270.7	[1],[2]	192.7
Appalachian Power Co [Member]
Net Income (Loss)	367.8	331.3		369.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.9)	(0.7)		(0.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(3.1)	(1.2)		(1.4)
Pension and OPEB Funded Status, Net of Tax	(2.6)	11.6		(3.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(6.6)	9.7		(5.6)
TOTAL COMPREHENSIVE INCOME (LOSS)	361.2	341		363.5
Indiana Michigan Power Co [Member]
Net Income (Loss)	261.3	186.7		239.9
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.6	1.3		1.3
Pension and OPEB Funded Status, Net of Tax	(0.6)	2.8		(0.8)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	1	4.1		0.5
TOTAL COMPREHENSIVE INCOME (LOSS)	262.3	190.8		240.4
Ohio Power Co [Member]
Net Income (Loss)	325.5	323.9		282.2
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(1.3)	(1.1)		(1.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1.3)	(1.1)		(1.3)
TOTAL COMPREHENSIVE INCOME (LOSS)	324.2	322.8		280.9
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	83.2	72		100
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(1)	(0.8)		(0.8)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1)	(0.8)		(0.8)
TOTAL COMPREHENSIVE INCOME (LOSS)	82.2	71.2		99.2
Southwestern Electric Power Co [Member]
Net Income (Loss)	152.2	137.5		169.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	4	1.4		1.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1.4)	(0.7)		(0.7)
Pension and OPEB Funded Status, Net of Tax	(3.1)	4.7		(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.5)	5.4		0
TOTAL COMPREHENSIVE INCOME (LOSS)	151.7	142.9		169.7
Total Comprehensive Income Attributable to Noncontrolling Interest	5	12.8		4.1
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	$ 146.7	$ 130.1		$ 165.6
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flow Hedges, Tax	$ 3.9	$ (1.4)	$ (8.8)
Securities Available for Sale, Tax	0	1.9	0.7
Amortization of Pension and OPEB Deferred Costs, Tax	(1.4)	0.6	0.3
Pension and OPEB Funded Status, Tax	(8.8)	46.7	(7.9)
AEP Texas Inc. [Member]
Cash Flow Hedges, Tax	0.3	0.5	0.6
Amortization of Pension and OPEB Deferred Costs, Tax	0.1	0.1	0.2
Pension and OPEB Funded Status, Tax	(0.3)	0.6	0.5
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.2)	(0.4)	(0.4)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.8)	(0.6)	(0.8)
Pension and OPEB Funded Status, Tax	(0.7)	6.3	(1.9)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.4	0.7	0.7
Pension and OPEB Funded Status, Tax	(0.2)	1.5	(0.4)
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.4)	(0.6)	(0.7)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.3)	(0.4)	(0.4)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	1.1	0.8	0.9
Amortization of Pension and OPEB Deferred Costs, Tax	(0.4)	(0.4)	(0.4)
Pension and OPEB Funded Status, Tax	$ (0.8)	$ 2.5	$ (0.5)

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			$ 1,552.9															$ 1,243									$ 309.9
Common Stock, Dividends, Per Share, Declared	$ 2.27
Beginning 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
Beginning Balance, Shares at Dec. 31, 2015	511,389,173									511,400,000
Issuance of Common Stock, Value	$ 34.2									$ 4.3						29.9
Issuance of Common Stock, Shares	659,347									600,000
Capital Contributions from Parent		53															53
Capital Contributions from Member		53	212															212
Common Stock Dividends	$ (1,121)																							(1,116.8)	[1]
Common Stock Dividends		(34)			(255)	(125)	(150)	(5)	(120)																	(34)		(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)	610.9								165.6															610.9								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																	146.6	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)
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									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 Parent		200															200
Capital Contributions from Member		200	361.6															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)	1,912.6								124.7															1,912.6								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	270.7	[2],[3]	331.3	186.7	323.9	72	137.5																	310.5	270.7	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
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			2,589.9															1,816.6									773.3
Common Stock, Dividends, Per Share, Declared	$ 2.53
Issuance of Common Stock, Value	$ 73.6									$ 8						65.6
Issuance of Common Stock, Shares	1,239,392									1,300,000
Capital Contributions from Parent		200															200
Capital Contributions from Member		200	664															664
Common Stock Dividends	$ (1,255.5)																							(1,251.1)	[1]
Common Stock Dividends					(160)	(124.7)	(337.5)	$ (50)	(65)																			(160)	(124.7)	(337.5)	(50)	(65)
ASU 2018-02 Adoption	(3)	(0.9)			0.4	(2.4)	0.4	0.5	(1.3)															14		1.8		0.1	0.3			(0.4)	(17)	[4]	(2.7)	[4]	0.3	[4]	(2.7)	[4]	0.4	0.5	(0.9)	[4]
ASU 2016-01 Adoption	0																							11.9									(11.9)	[4]
Common Stock Dividends									(4.3)																																				(4.4)	(4.3)
Stockholders' Equity, Other	23.1															21.8																													1.3
Net Income (Loss)	1,923.8								147.2															1,923.8								147.2
Net Income (Loss) Attributable to Noncontrolling Interests	7.5								5																																				7.5	5
Net Income (Loss)	1,931.3	211.3	315.9		367.8	261.3	325.5	83.2	152.2																	211.3	315.9	367.8	261.3	325.5	83.2
Other Comprehensive Income (Loss)	(23.7)	0.2			(6.6)	1	(1.3)	(1)	(0.5)																								(23.7)		0.2		(6.6)		1		(1.3)	(1)	(0.5)
Distribution of CSW Energy, Inc to Parent		0
Ending Balance at Dec. 31, 2018	$ 19,059.4	$ 2,580.5			$ 4,006.1	$ 2,352.8	$ 2,297.4	$ 1,248	$ 2,315.6	$ 3,337.4	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,486.1	$ 1,257.9		$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 9,325.3		$ 1,337.7		$ 1,922	$ 1,329.1	$ 1,136.4	$ 724.7	$ 1,508.4	$ (120.4)		$ (15.1)		$ (5)		$ (13.8)		$ 1	$ 2.1	$ (5.4)		$ 31	$ 0.3
Ending Balance, Shares at Dec. 31, 2018	513,450,036							10,482,000		513,500,000
TOTAL MEMBER'S EQUITY			$ 3,569.8															$ 2,480.6									$ 1,089.2
[1]	(a)Cash dividends declared per AEP common share were $2.53, $2.39 and $2.27 for the years ended December 31, 2018, 2017 and 2016, respectively.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[3]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[4]	See Note 2 - New Accounting Pronouncements for additional information.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents		$ 234.1	$ 214.6
Restricted Cash		210	198
Other Temporary Investments		159.1	161.7
Accounts Receivable:
Customers		699	643.9
Accrued Unbilled Revenues		209.3	230.2
Pledged Accounts Receivable - AEP Credit		999.8	954.2
Miscellaneous		55.2	101.2
Allowance for Uncollectible Accounts		(36.8)	(38.5)
Total Accounts Receivable		1,926.5	1,891
Fuel		341.5	387.7
Materials and Supplies		579.6	565.5
Risk Management Assets		162.8	126.2
Regulatory Asset for Under-Recovered Fuel Costs		150.1	292.5
Margin Deposits		141.4	105.5
Prepayments and Other Current Assets		208.8	310.4
TOTAL CURRENT ASSETS		4,113.9	4,253.1
Property, Plant and Equipment
Generation		21,699.9	20,760.5
Transmission		21,531	18,972.5
Distribution		21,195.4	19,868.5
Other Property, Plant and Equipment		4,265	3,706.3
Construction Work in Progress		4,393.9	4,120.7
Total Property, Plant and Equipment		73,085.2	67,428.5
Accumulated Depreciation and Amortization		17,986.1	17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		55,099.1	50,261.5
Other Noncurrent Assets
Regulatory Assets		3,310.4	3,587.6
Securitized Assets		920.6	1,211.2
Spent Nuclear Fuel and Decommissioning Trusts		2,474.9	2,527.6
Goodwill		52.5	52.5
Long-term Risk Management Assets		254	282.1
Deferred Charges and Other Noncurrent Assets		2,577.4	2,553.5
TOTAL OTHER NONCURRENT ASSETS		9,589.8	10,214.5
TOTAL ASSETS		68,802.8	64,729.1
Current Liabilities
Accounts Payable		1,874.3	2,065.3
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	750	718
Other Short-term Debt		1,160	920.6
Total Short-term Debt		1,910	1,638.6
Long-term Debt Due Within One Year		1,698.5	1,753.7
Risk Management Liabilities		55	61.6
Customer Deposits		412.2	357
Accrued Taxes		1,218	1,115.5
Accrued Interest		231.7	234.5
Obligations Under Capital Leases		55.5	59
Regulatory Liability for Over-Recovered Fuel Costs		58.6	11.9
Other Current Liabilities		1,190.5	1,033.2
TOTAL CURRENT LIABILITIES		8,648.8	8,271.3
Noncurrent Liabilities
Long-term Debt		21,648.2	19,419.6
Long-term Debt - Affiliated		0	0
Long-term Risk Management Liabilities		263.4	322
Deferred Income Taxes		7,086.5	6,813.9
Regulatory Liabilities and Deferred Investment Tax Credits		8,540.3	8,422.3
Asset Retirement Obligations		2,287.7	1,925.5
Employee Benefits and Pension Obligations		377.1	398.1
Obligations Under Capital Leases		233.5	238.8
Deferred Credits and Other Noncurrent Liabilities		782.6	830.9
TOTAL NONCURRENT LIABILITIES		40,985.8	38,132.3
TOTAL LIABILITIES		49,634.6	46,403.6
Rate Matters
Commitments and Contingencies
Redeemable Noncontrolling Interest		69.4	0
Contingently Redeemable Performance Share Awards		39.4	11.9
Total Mezzanine Equity		108.8	11.9
Equity
Common Stock		3,337.4	3,329.4
Paid-in Capital		6,486.1	6,398.7
Retained Earnings		9,325.3	8,626.7
Accumulated Other Comprehensive Income (Loss)		(120.4)	(67.8)
TOTAL COMMON SHAREHOLDERS' EQUITY		19,028.4	18,287
Noncontrolling Interests		31	26.6
TOTAL EQUITY		19,059.4	18,313.6
TOTAL LIABILITIES AND EQUITY		68,802.8	64,729.1
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents		3.1	2
Restricted Cash		156.7	155.2
Advances to Affiliates		8	111.9
Accounts Receivable:
Customers		110.9	105.3
Affiliated Companies		15	12.3
Accrued Unbilled Revenues		70.4	75.8
Miscellaneous		1.9	1.3
Allowance for Uncollectible Accounts		(1.3)	(0.7)
Total Accounts Receivable		196.9	194
Fuel		8.8	3.6
Materials and Supplies		52.8	52
Risk Management Assets		0	0.5
Accrued Tax Benefits		44.9	41
Prepayments and Other Current Assets		5.3	3.6
TOTAL CURRENT ASSETS		476.5	563.8
Property, Plant and Equipment
Generation		352.1	350.7
Transmission		3,683.6	3,053.6
Distribution		4,043.2	3,718.6
Other Property, Plant and Equipment		727.9	461
Construction Work in Progress		836.2	835.7
Total Property, Plant and Equipment		9,643	8,419.6
Accumulated Depreciation and Amortization		1,651.2	1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,991.8	6,825.1
Other Noncurrent Assets
Regulatory Assets		430	378.7
Securitized Assets		649.1	891.2
Deferred Charges and Other Noncurrent Assets		56.3	114.8
TOTAL OTHER NONCURRENT ASSETS		1,135.4	1,384.7
TOTAL ASSETS		9,603.7	8,773.6
Current Liabilities
Advances from Affiliates		216	0
Accounts Payable		276.5	379.4
Affiliated Companies		30.3	30.2
Short-term Debt:
Long-term Debt Due Within One Year		501.1	266.1
Risk Management Liabilities		0.2	0
Accrued Taxes		75.5	77.2
Accrued Interest		37.3	42.2
Oklaunion Purchase Power Agreement		24.3	0
Obligations Under Capital Leases		4.5	4.2
Other Current Liabilities		98.3	76.4
TOTAL CURRENT LIABILITIES		1,259.5	871.5
Noncurrent Liabilities
Long-term Debt		3,380.2	3,383.2
Deferred Income Taxes		913.1	913.1
Regulatory Liabilities and Deferred Investment Tax Credits		1,344.3	1,320.5
Oklaunion Purchase Power Agreement		22.1	52
Obligations Under Capital Leases		24	18.5
Deferred Credits and Other Noncurrent Liabilities		104	63.4
TOTAL NONCURRENT LIABILITIES		5,763.7	5,732.2
TOTAL LIABILITIES		7,023.2	6,603.7
Rate Matters
Commitments and Contingencies
Equity
Paid-in Capital		1,257.9	1,057.9
Retained Earnings		1,337.7	1,124.6
Accumulated Other Comprehensive Income (Loss)		(15.1)	(12.6)
TOTAL EQUITY		2,580.5	2,169.9
TOTAL LIABILITIES AND EQUITY		9,603.7	8,773.6
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0	0
Advances to Affiliates		96.9	146.3
Accounts Receivable:
Customers		11.8	15
Affiliated Companies		61	93.2
Miscellaneous		0	1.3
Total Accounts Receivable		72.8	109.5
Materials and Supplies		19	13.6
Accrued Tax Benefits		33.4	49.4
Prepayments and Other Current Assets		3.4	7.6
TOTAL CURRENT ASSETS		225.5	326.4
Property, Plant and Equipment
Transmission		6,515.8	5,319.7
Other Property, Plant and Equipment		174	126.8
Construction Work in Progress		1,578.3	1,324
Total Property, Plant and Equipment		8,268.1	6,770.5	[2]
Accumulated Depreciation and Amortization		271.9	152.6	[2]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,996.2	6,617.9	[2],[3]
Other Noncurrent Assets
Regulatory Assets		12.9	11.7
Deferred Property Taxes		157.9	125
Deferred Charges and Other Noncurrent Assets		1.6	1.1
TOTAL OTHER NONCURRENT ASSETS		172.4	137.8
TOTAL ASSETS		8,394.1	7,082.1	[2]
Current Liabilities
Advances from Affiliates		45.4	15.7
Accounts Payable		347.2	484.5
Affiliated Companies		56	66.1
Short-term Debt:
Long-term Debt Due Within One Year		85	50
Accrued Taxes		288.9	231.5
Accrued Interest		15.9	15
Obligations Under Capital Leases		0.1	0.1
Other Current Liabilities		3.8	4.1
TOTAL CURRENT LIABILITIES		842.2	866.9
Noncurrent Liabilities
Long-term Debt		2,738	2,500.4
Deferred Income Taxes		704.4	600.4
Regulatory Liabilities and Deferred Investment Tax Credits		521.3	493.8
Obligations Under Capital Leases		0	0.1
Deferred Credits and Other Noncurrent Liabilities		18.4	30.7
TOTAL NONCURRENT LIABILITIES		3,982.1	3,625.3
TOTAL LIABILITIES		4,824.3	4,492.2
Rate Matters
Commitments and Contingencies
Equity
Members' Capital		2,480.6	1,816.6
Retained Earnings		1,089.2	773.3
TOTAL MEMBER'S EQUITY		3,569.8	2,589.9
TOTAL LIABILITIES AND EQUITY		8,394.1	7,082.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		4.2	2.9
Restricted Cash		25.6	16.3
Advances to Affiliates		23	23.5
Accounts Receivable:
Customers		146.5	123.1
Affiliated Companies		73.4	69.3
Accrued Unbilled Revenues		63.5	74.1
Miscellaneous		2.3	1.1
Allowance for Uncollectible Accounts		(2.3)	(3.7)
Total Accounts Receivable		283.4	263.9
Fuel		61.3	89.3
Materials and Supplies		100.1	99.5
Risk Management Assets		57.2	24.9
Regulatory Asset for Under-Recovered Fuel Costs		99.6	88.8
Prepayments and Other Current Assets		44.3	27.1
TOTAL CURRENT ASSETS		698.7	636.2
Property, Plant and Equipment
Generation		6,509.6	6,446.9
Transmission		3,317.7	3,019.9
Distribution		3,989.4	3,763.8
Other Property, Plant and Equipment		485.8	427.9
Construction Work in Progress		490.2	483
Total Property, Plant and Equipment		14,792.7	14,141.5
Accumulated Depreciation and Amortization		4,124.4	3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,668.3	10,245.1
Other Noncurrent Assets
Regulatory Assets		475.8	573.9
Securitized Assets		258.7	282.3
Long-term Risk Management Assets		0.9	1.1
Deferred Charges and Other Noncurrent Assets		188.1	190
TOTAL OTHER NONCURRENT ASSETS		923.5	1,047.3
TOTAL ASSETS		12,290.5	11,928.6
Current Liabilities
Advances from Affiliates		205.6	186
Accounts Payable		263.8	264.9
Affiliated Companies		84	92.7
Short-term Debt:
Long-term Debt Due Within One Year		430.7	249.2
Risk Management Liabilities		0.4	1.3
Customer Deposits		88.4	86.1
Accrued Taxes		89.3	94.5
Obligations Under Capital Leases		6.1	6.6
Other Current Liabilities		191.8	149.5
TOTAL CURRENT LIABILITIES		1,354	1,124.2
Noncurrent Liabilities
Long-term Debt		3,631.9	3,730.9
Long-term Risk Management Liabilities		0.2	0.2
Deferred Income Taxes		1,625.8	1,565.7
Regulatory Liabilities and Deferred Investment Tax Credits		1,449.7	1,454.9
Asset Retirement Obligations		107.1	100.2
Employee Benefits and Pension Obligations		57.1	73.3
Obligations Under Capital Leases		33.7	34.9
Deferred Credits and Other Noncurrent Liabilities		58.6	74.7
TOTAL NONCURRENT LIABILITIES		6,930.4	6,999.9
TOTAL LIABILITIES		8,284.4	8,124.1
Rate Matters
Commitments and Contingencies
Equity
Common Stock		260.4	260.4
Paid-in Capital		1,828.7	1,828.7
Retained Earnings		1,922	1,714.1
Accumulated Other Comprehensive Income (Loss)		(5)	1.3
TOTAL EQUITY		4,006.1	3,804.5
TOTAL LIABILITIES AND EQUITY		12,290.5	11,928.6
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.4	1.3
Advances to Affiliates		12.7	12.4
Accounts Receivable:
Customers		63.1	56.4
Affiliated Companies		75	50
Accrued Unbilled Revenues		3.6	7.3
Miscellaneous		1.4	2
Allowance for Uncollectible Accounts		(0.1)	(0.1)
Total Accounts Receivable		143	115.6
Fuel		37.3	31.4
Materials and Supplies		167.3	160.6
Risk Management Assets		8.6	7.6
Accrued Tax Benefits		26.6	58.4
Regulatory Asset for Under-Recovered Fuel Costs		0	15
Accrued Reimbursement of Spent Nuclear Fuel Costs		7.9	10.8
Prepayments and Other Current Assets		24.6	20.9
TOTAL CURRENT ASSETS		430.4	434
Property, Plant and Equipment
Generation		4,887.2	4,445.9
Transmission		1,576.8	1,504
Distribution		2,249.7	2,069.3
Other Property, Plant and Equipment		583.8	595.2
Construction Work in Progress		465.3	460.2
Total Property, Plant and Equipment		9,762.8	9,074.6
Accumulated Depreciation and Amortization		3,151.6	3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,611.2	6,050.4
Other Noncurrent Assets
Regulatory Assets		512.5	579.4
Spent Nuclear Fuel and Decommissioning Trusts		2,474.9	2,527.6
Long-term Risk Management Assets		0.6	0.7
Deferred Charges and Other Noncurrent Assets		193	179.9
TOTAL OTHER NONCURRENT ASSETS		3,181	3,287.6
TOTAL ASSETS		10,222.6	9,772
Current Liabilities
Advances from Affiliates		1.1	211.6
Accounts Payable		174.7	154.5
Affiliated Companies		70.2	98.3
Short-term Debt:
Long-term Debt Due Within One Year		155.4	474.7
Risk Management Liabilities		0.3	3.5
Customer Deposits		38	37.7
Accrued Taxes		90.7	81.3
Accrued Interest		37.3	37.5
Obligations Under Capital Leases		5.3	5.8
Regulatory Liability for Over-Recovered Fuel Costs		27.4	2.7
Other Current Liabilities		103	109.5
TOTAL CURRENT LIABILITIES		698.1	1,211.3
Noncurrent Liabilities
Long-term Debt		2,880	2,270.4
Long-term Risk Management Liabilities		0.1	0.1
Deferred Income Taxes		948	953.8
Regulatory Liabilities and Deferred Investment Tax Credits		1,574.5	1,708.7
Asset Retirement Obligations		1,681.3	1,321.6
Obligations Under Capital Leases		33.4	34.3
Deferred Credits and Other Noncurrent Liabilities		87.8	88.5
TOTAL NONCURRENT LIABILITIES		7,171.7	6,343.1
TOTAL LIABILITIES		7,869.8	7,554.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,329.1	1,192.2
Accumulated Other Comprehensive Income (Loss)		(13.8)	(12.1)
TOTAL EQUITY		2,352.8	2,217.6
TOTAL LIABILITIES AND EQUITY		10,222.6	9,772
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		4.9	3.1
Restricted Cash		27.6	26.6
Accounts Receivable:
Customers		111.1	67.8
Affiliated Companies		70.8	70.2
Accrued Unbilled Revenues		21.4	29.7
Miscellaneous		0.3	1.9
Allowance for Uncollectible Accounts		(1)	(0.6)
Total Accounts Receivable		202.6	169
Materials and Supplies		42.9	41.9
Renewable Energy Credits		25.9	25
Risk Management Assets		0	0.6
Regulatory Asset for Under-Recovered Fuel Costs		0.4	115.9
Prepayments and Other Current Assets		15.3	15.8
TOTAL CURRENT ASSETS		319.6	397.9
Property, Plant and Equipment
Transmission		2,544.3	2,419.2
Distribution		4,942.3	4,626.4
Other Property, Plant and Equipment		574.8	495.9
Construction Work in Progress		432.1	410.1
Total Property, Plant and Equipment		8,493.5	7,951.6
Accumulated Depreciation and Amortization		2,218.6	2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,274.9	5,766.8
Other Noncurrent Assets
Regulatory Assets		387.5	652.8
Securitized Assets		12.9	37.7
Deferred Charges and Other Noncurrent Assets		441	406.5
TOTAL OTHER NONCURRENT ASSETS		841.4	1,097
TOTAL ASSETS		7,435.9	7,261.7
Current Liabilities
Advances from Affiliates		114.1	87.8
Accounts Payable		211.9	205.8
Affiliated Companies		102.9	118.2
Short-term Debt:
Long-term Debt Due Within One Year		47.9	397
Risk Management Liabilities		5.8	6.4
Customer Deposits		113.1	69.2
Accrued Taxes		537.8	512.5
Obligations Under Capital Leases		2.9	4.3
Other Current Liabilities		214.2	196.9
TOTAL CURRENT LIABILITIES		1,347.7	1,593.8
Noncurrent Liabilities
Long-term Debt		1,668.7	1,322.3
Long-term Risk Management Liabilities		93.8	126
Deferred Income Taxes		763.3	762.9
Regulatory Liabilities and Deferred Investment Tax Credits		1,221.2	1,100.2
Obligations Under Capital Leases		9.2	7.9
Deferred Credits and Other Noncurrent Liabilities		43.8	46.2
TOTAL NONCURRENT LIABILITIES		3,790.8	3,357.6
TOTAL LIABILITIES		5,138.5	4,951.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		1,136.4	1,148.4
Accumulated Other Comprehensive Income (Loss)		1	1.9
TOTAL EQUITY		2,297.4	2,310.3
TOTAL LIABILITIES AND EQUITY		7,435.9	7,261.7
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		2	1.6
Accounts Receivable:
Customers		32.5	32.5
Affiliated Companies		26.2	32.9
Miscellaneous		5.7	4.1
Allowance for Uncollectible Accounts		(0.1)	(0.1)
Total Accounts Receivable		64.3	69.4
Fuel		12.3	12.5
Materials and Supplies		44.8	42
Risk Management Assets		10.4	6.4
Accrued Tax Benefits		14.7	28.1
Regulatory Asset for Under-Recovered Fuel Costs		0	36.7
Prepayments and Other Current Assets		9.4	8.6
TOTAL CURRENT ASSETS		157.9	205.3
Property, Plant and Equipment
Generation		1,577	1,577.2
Transmission		892.3	858.8
Distribution		2,572.8	2,445.1
Other Property, Plant and Equipment		303.5	287.4
Construction Work in Progress		94	111.3
Total Property, Plant and Equipment		5,439.6	5,279.8
Accumulated Depreciation and Amortization		1,472.9	1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,966.7	3,886.2
Other Noncurrent Assets
Regulatory Assets		369	368.1
Employee Benefits and Pension Assets		31.7	40
Deferred Charges and Other Noncurrent Assets		7.1	8.7
TOTAL OTHER NONCURRENT ASSETS		407.8	416.8
TOTAL ASSETS		4,532.4	4,508.3
Current Liabilities
Advances from Affiliates		105.5	149.6
Accounts Payable		126.9	102.4
Affiliated Companies		47.1	48
Short-term Debt:
Long-term Debt Due Within One Year		375.5	0.5
Risk Management Liabilities		1	0
Customer Deposits		58.6	54.1
Accrued Taxes		22.4	22.6
Accrued Interest		13.9	14.1
Obligations Under Capital Leases		2.8	3.5
Regulatory Liability for Over-Recovered Fuel Costs		20.1	0
Other Current Liabilities		50.6	44.7
TOTAL CURRENT LIABILITIES		821.6	436
Noncurrent Liabilities
Long-term Debt		911.5	1,286
Deferred Income Taxes		607.8	642
Regulatory Liabilities and Deferred Investment Tax Credits		864.7	853.5
Asset Retirement Obligations		46.3	53
Obligations Under Capital Leases		9.5	8.3
Deferred Credits and Other Noncurrent Liabilities		32.5	22.5
TOTAL NONCURRENT LIABILITIES		2,462.8	2,857
TOTAL LIABILITIES		3,284.4	3,293
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		724.7	691.5
Accumulated Other Comprehensive Income (Loss)		2.1	2.6
TOTAL EQUITY		1,248	1,215.3
TOTAL LIABILITIES AND EQUITY		4,532.4	4,508.3
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		24.5	1.6
Advances to Affiliates		83.4	2
Accounts Receivable:
Customers		24.5	70.9
Affiliated Companies		28.8	30.2
Miscellaneous		20.2	25.8
Allowance for Uncollectible Accounts		(0.7)	(1.3)
Total Accounts Receivable		72.8	125.6
Fuel		120.5	123.6
Materials and Supplies		67.5	67.9
Risk Management Assets		4.8	6.4
Regulatory Asset for Under-Recovered Fuel Costs		18.8	14.1
Prepayments and Other Current Assets		22.2	39.2
TOTAL CURRENT ASSETS		414.5	380.4
Property, Plant and Equipment
Generation		4,672.6	4,624.9
Transmission		1,866.9	1,679.8
Distribution		2,178.6	2,095.8
Other Property, Plant and Equipment		762.7	684.1
Construction Work in Progress		199.3	233.2
Total Property, Plant and Equipment		9,680.1	9,317.8
Accumulated Depreciation and Amortization		2,808.3	2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,871.8	6,632
Other Noncurrent Assets
Regulatory Assets		230.8	220.6
Deferred Charges and Other Noncurrent Assets		111.2	109.9
TOTAL OTHER NONCURRENT ASSETS		342	330.5
TOTAL ASSETS		7,628.3	7,342.9
Current Liabilities
Advances from Affiliates		0	118.7
Accounts Payable		129.1	160.4
Affiliated Companies		64.2	63.7
Short-term Debt:
Other Short-term Debt		0	22
Long-term Debt Due Within One Year		59.7	3.7
Risk Management Liabilities		0.4	0.2
Customer Deposits		64.5	62.1
Accrued Taxes		42.8	39
Accrued Interest		34.7	38.9
Obligations Under Capital Leases		10.2	11.2
Regulatory Liability for Over-Recovered Fuel Costs		11.1	8.7
Other Current Liabilities		107.3	78.7
TOTAL CURRENT LIABILITIES		512.9	598.6
Noncurrent Liabilities
Long-term Debt		2,653.7	2,438.2
Long-term Risk Management Liabilities		2.2	0
Deferred Income Taxes		902.8	917.7
Regulatory Liabilities and Deferred Investment Tax Credits		923	896.4
Asset Retirement Obligations		191.3	160.3
Employee Benefits and Pension Obligations		24.8	19.5
Obligations Under Capital Leases		50.6	57.8
Deferred Credits and Other Noncurrent Liabilities		51.4	19.9
TOTAL NONCURRENT LIABILITIES		4,799.8	4,509.8
TOTAL LIABILITIES		5,312.7	5,108.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,508.4	1,426.6
Accumulated Other Comprehensive Income (Loss)		(5.4)	(4)
TOTAL COMMON SHAREHOLDERS' EQUITY		2,315.3	2,234.9
Noncontrolling Interests		0.3	(0.4)
TOTAL EQUITY		2,315.6	2,234.5
TOTAL LIABILITIES AND EQUITY		$ 7,628.3	$ 7,342.9
[1]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[3]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 234.1	$ 214.6
Restricted Cash	210	198
Other Temporary Investments	159.1	161.7
Fuel	341.5	387.7
Property, Plant and Equipment
Other Property, Plant and Equipment	4,265	3,706.3
Accumulated Depreciation and Amortization	17,986.1	17,167
Current Liabilities
Long-term Debt Due Within One Year	1,698.5	1,753.7
Accrued Interest	231.7	234.5
Other Noncurrent Assets
Securitized Assets	920.6	1,211.2
Noncurrent Liabilities
Long-term Debt	$ 21,648.2	$ 19,419.6
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	513,450,036	512,210,644
Treasury Stock, Shares	20,204,160	20,205,046
Subsidiaries [Member]
Current Assets
Restricted Cash	$ 210	$ 198
Other Temporary Investments	152.7	155.4
Current Liabilities
Long-term Debt Due Within One Year	406.5	406.9
Noncurrent Liabilities
Long-term Debt	1,109.2	1,401.5
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents	3.1	2
Restricted Cash	156.7	155.2
Fuel	8.8	3.6
Property, Plant and Equipment
Other Property, Plant and Equipment	727.9	461
Accumulated Depreciation and Amortization	1,651.2	1,594.5
Current Liabilities
Long-term Debt Due Within One Year	501.1	266.1
Accrued Interest	37.3	42.2
Other Noncurrent Assets
Securitized Assets	649.1	891.2
Noncurrent Liabilities
Long-term Debt	3,380.2	3,383.2
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member]
Current Liabilities
Long-term Debt Due Within One Year	251.1	236.1
Accrued Interest	11.3	15.9
Other Noncurrent Assets
Securitized Assets	636.8	869.5
Noncurrent Liabilities
Long-term Debt	540.1	790.1
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents	0	0
Property, Plant and Equipment
Other Property, Plant and Equipment	174	126.8
Accumulated Depreciation and Amortization	271.9	152.6	[1]
Current Liabilities
Long-term Debt Due Within One Year	85	50
Accrued Interest	15.9	15
Noncurrent Liabilities
Long-term Debt	2,738	2,500.4
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	4.2	2.9
Restricted Cash	25.6	16.3
Fuel	61.3	89.3
Property, Plant and Equipment
Other Property, Plant and Equipment	485.8	427.9
Accumulated Depreciation and Amortization	4,124.4	3,896.4
Current Liabilities
Long-term Debt Due Within One Year	430.7	249.2
Other Noncurrent Assets
Securitized Assets	258.7	282.3
Noncurrent Liabilities
Long-term Debt	$ 3,631.9	$ 3,730.9
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	$ 2.4	$ 1.3
Fuel	37.3	31.4
Property, Plant and Equipment
Other Property, Plant and Equipment	583.8	595.2
Accumulated Depreciation and Amortization	3,151.6	3,024.2
Current Liabilities
Long-term Debt Due Within One Year	155.4	474.7
Accrued Interest	37.3	37.5
Noncurrent Liabilities
Long-term Debt	$ 2,880	$ 2,270.4
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	$ 76.8	$ 96.3
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	4.9	3.1
Restricted Cash	27.6	26.6
Property, Plant and Equipment
Other Property, Plant and Equipment	574.8	495.9
Accumulated Depreciation and Amortization	2,218.6	2,184.8
Current Liabilities
Long-term Debt Due Within One Year	47.9	397
Other Noncurrent Assets
Securitized Assets	12.9	37.7
Noncurrent Liabilities
Long-term Debt	$ 1,668.7	$ 1,322.3
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 47.8	$ 47
Other Noncurrent Assets
Securitized Assets	13	38
Noncurrent Liabilities
Long-term Debt	0	47.5
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	2	1.6
Fuel	12.3	12.5
Property, Plant and Equipment
Other Property, Plant and Equipment	303.5	287.4
Accumulated Depreciation and Amortization	1,472.9	1,393.6
Current Liabilities
Long-term Debt Due Within One Year	375.5	0.5
Accrued Interest	13.9	14.1
Noncurrent Liabilities
Long-term Debt	$ 911.5	$ 1,286
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	$ 24.5	$ 1.6
Fuel	120.5	123.6
Property, Plant and Equipment
Other Property, Plant and Equipment	762.7	684.1
Accumulated Depreciation and Amortization	2,808.3	2,685.8
Current Liabilities
Long-term Debt Due Within One Year	59.7	3.7
Accrued Interest	34.7	38.9
Noncurrent Liabilities
Long-term Debt	$ 2,653.7	$ 2,438.2
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	$ 22	$ 0
Fuel	35.7	41.5
Property, Plant and Equipment
Other Property, Plant and Equipment	276.9	266.7
Accumulated Depreciation and Amortization	$ 174.6	$ 165.9
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Operating Activites
NET INCOME (LOSS)	$ 1,931.3	$ 1,928.9		$ 618
Income (Loss) from Discontinued Operations, Net of Tax	0	0		(2.5)
Income (Loss) from Continuing Operations	1,931.3	1,928.9		620.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	2,286.6	1,997.2		1,962.3
Deferred Income Taxes	104.3	901.5		(50)
Asset Impairments and Other Related Charges	70.6	87.1		2,267.8
Carrying Costs Income	(6.6)	(18.6)		(16.2)
Allowance for Equity Funds Used During Construction	(132.5)	(93.7)		(113.2)
Mark-to-Market of Risk Management Contracts	(66.4)	(23.3)		150.8
Amortization of Nuclear Fuel	113.8	129.1		128.6
Pension and Postemployment Benefit Reserves	(42.8)	27.8		21.6
Pension Contributions to Qualified Plan Trust	0	(93.3)		(84.8)
Property Taxes	(59.1)	(29.5)		(19)
Deferred Fuel Over/Under-Recovery, Net	189.7	84.4		(65.5)
Gain on Sale of Merchant Generation Assets	0	(226.4)		0
Deferral of Ohio Capacity Costs, Net	67.7	83.2		88.1
Provision for Refund - Global Settlement	(5.5)	(98.2)		120.3
Disposition of Tanners Creek Plant Site	0	0		(93.5)
Change in Other Noncurrent Assets	119.8	(423.9)		(454.6)
Change in Other Noncurrent Liabilities	129	181.7		15.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	145.9	28.5		(226.6)
Fuel, Materials and Supplies	20.7	17.9		60.2
Accounts Payable	36.6	(58)		164.9
Accrued Taxes, Net	153.2	91.9		42.8
Other Current Assets	10.5	(60.7)		14.2
Other Current Liabilities	149.8	(181.8)		(28.5)
Net Cash Flows from (Used for) Continuing Operating Activities	5,223.2	4,270.4		4,521.8
Investing Activities
Construction Expenditures	(6,310.9)	(5,691.3)		(4,781.1)
Purchases of Investment Securities	(2,067.8)	(2,314.7)		(3,002.3)
Sales of Investment Securities	2,010	2,256.3		2,957.7
Acquisitions of Nuclear Fuel	(46.1)	(108)		(128.5)
Acquisitions of Assets	(14.6)	(6.8)		(107.9)
Proceeds from Sale of Merchant Generation Assets	0	2,159.6		0
Other Investing Activities	75.8	48.5		15.5
Net Cash Flows from (Used for) Continuing Investing Activities	(6,353.6)	(3,656.4)		(5,046.6)
Financing Activities
Issuance of Common Stock, Net	73.6	12.2		34.2
Issuance of Long-term Debt	4,945.7	3,854.1		2,594.9
Commercial Paper and Credit Facility Borrowings	205.6	0		0
Change in Short-term Debt, Net	271.4	(74.4)		913
Retirement of Long-term Debt	(2,782)	(3,087.9)		(1,794.9)
Commercial Paper and Credit Facility Repayments	205.6	0		0
Make Whole Premium on Extinguishment of Long-term Debt	(13.5)	(46.1)		0
Principal Payments for Capital Lease Obligations	(65.1)	(67.3)		(106.6)
Dividends Paid on Common Stock	(1,255.5)	(1,191.9)		(1,121)
Other Financing Activities	(12.7)	(3.6)		(15.7)
Net Cash Flows from (Used for) Continuing Financing Activities	1,161.9	(604.9)		503.9
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Cash Flows from (Used for) Discontinued Operating Activities	0	0		(2.5)
Net Cash Flows from (Used for) Discontinued Investing Activities	0	0		0
Net Cash Flows from (Used for) Discontinued Financing Activities	0	0		0
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	31.5	9.1		(23.4)
Cash and Cash Equivalents at Beginning of Period	214.6
Cash, Cash Equivalents and Restricted Cash at End of Period	444.1	412.6		403.5
Cash and Cash Equivalents at End of Period	234.1	214.6
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	939.3	858.3		848.5
Net Cash Paid (Received) for Income Taxes	(24.7)	(1.1)		29.5
Noncash Acquisitions Under Capital Leases	55.6	60.7		86.1
Construction Expenditures Included in Current Liabilities as of December 31,	1,120.4	1,330.8		858
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	4	0		2.1
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	2.2	2.6		0.7
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC	84	0		0
AEP Texas Inc. [Member]
Operating Activites
NET INCOME (LOSS)	211.3	310.5		146.6
Income (Loss) from Discontinued Operations, Net of Tax	0	0		(48.8)
Income (Loss) from Continuing Operations	211.3	310.5		195.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	499.6	450.1		413.9
Deferred Income Taxes	(16.5)	63.3		29.5
Asset Impairments and Other Related Charges				72.7
Allowance for Equity Funds Used During Construction	(20)	(6.8)		(9.2)
Mark-to-Market of Risk Management Contracts	0.7	(0.3)		(0.5)
Pension Contributions to Qualified Plan Trust	0	(8.8)		(8.2)
Change in Regulatory Asset - Catastrophe Reserve	(24.9)	(99.2)		(0.9)
Change in Other Noncurrent Assets	(35.4)	(49.4)		(44.1)
Change in Other Noncurrent Liabilities	44.9	8.8		(10.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(2.9)	(23.5)		(22.6)
Fuel, Materials and Supplies	(6)	3.2		5.9
Accounts Payable	(20.3)	30.8		(3)
Accrued Taxes, Net	(5.6)	(31.3)		(22.6)
Other Current Assets	0.8	0.6		(0.2)
Other Current Liabilities	26.2	(15.3)		(6.5)
Net Cash Flows from (Used for) Continuing Operating Activities	651.9	632.7		516.6
Investing Activities
Construction Expenditures	(1,428.8)	(990.9)		(640.9)
Change in Advances to Affiliates, Net	103.9	(103.3)		139
Other Investing Activities	35.2	18.9		10.4
Net Cash Flows from (Used for) Continuing Investing Activities	(1,289.7)	(1,075.3)		(491.5)
Financing Activities
Capital Contributions from Member	200	200		53
Issuance of Long-term Debt	494	749.6		199.2
Change in Advances from Affiliates, Net	216	(169.5)		117
Retirement of Long-term Debt	(266.1)	(323.1)		(428.7)
Principal Payments for Capital Lease Obligations	(4.7)	(3.9)		(3.4)
Dividends Paid on Common Stock	0	0		(34)
Other Financing Activities	1.2	(0.2)		0.8
Net Cash Flows from (Used for) Continuing Financing Activities	640.4	452.9		(96.1)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Cash Flows from (Used for) Discontinued Operating Activities	0	0		42.4
Net Cash Flows from (Used for) Discontinued Investing Activities	0	0		11.7
Net Cash Flows from (Used for) Discontinued Financing Activities	0	0		(44.6)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	2.6	10.3		(61.5)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	157.2	146.9		208.4
Cash and Cash Equivalents at Beginning of Period	2
Cash, Cash Equivalents and Restricted Cash at End of Period	159.8	157.2
Cash, Cash Equivalents and Restricted Cash at End of Period	159.8	157.2		146.9
Cash and Cash Equivalents at End of Period	3.1	2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	145.9	134.6		145.6
Net Cash Paid (Received) for Income Taxes	7.9	(28.3)		38.2
Noncash Acquisitions Under Capital Leases	10.6	8.2		7.1
Construction Expenditures Included in Current Liabilities as of December 31,	243.1	325.7		100.1
Distribution of CSW Energy, Inc to Parent	0	0		185.5
AEP Transmission Co [Member]
Operating Activites
NET INCOME (LOSS)	315.9	270.7	[1],[2]	192.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	133.9	95.7	[1],[3]	65.9
Deferred Income Taxes	98.9	271.5		223.1
Allowance for Equity Funds Used During Construction	(70.6)	(49)	[1],[4]	(52.3)
Property Taxes	(32.9)	(22.8)		(15.3)
Change in Other Noncurrent Assets	14.6	11		(2.8)
Change in Other Noncurrent Liabilities	17.4	27.5		4.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	36.7	(30.4)		(22.6)
Fuel, Materials and Supplies	(5.4)	(8.6)		(5)
Accounts Payable	(7.5)	23		14.3
Accrued Taxes, Net	73.4	16.3		143.8
Accrued Interest	0.9	4.5		2.6
Other Current Assets	(0.3)	(4.8)		0.1
Other Current Liabilities	(26.4)	0.2		0
Net Cash Flows from (Used for) Operating Activities	548.6	604.8		548.9
Investing Activities
Construction Expenditures	(1,526.4)	(1,513.4)		(1,159.5)
Change in Advances to Affiliates, Net	49.4	(79.2)		29
Acquisitions of Assets	(37.4)	(9.1)		(6.5)
Other Investing Activities	1.1	6.1		2
Net Cash Flows from (Used for) Investing Activities	(1,513.3)	(1,595.6)		(1,135)
Financing Activities
Capital Contributions from Member	664	361.6		212
Issuance of Long-term Debt	321	617.6		686.9
Change in Advances from Affiliates, Net	29.7	11.6		(12.8)
Retirement of Long-term Debt	(50)	0		(300)
Net Cash Flows from (Used for) Financing Activities	964.7	990.8		586.1
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	80.2	62.4		42
Net Cash Paid (Received) for Income Taxes	(30.7)	(107.3)		(235.1)
Noncash Acquisitions Under Capital Leases	0	0.2		0
Construction Expenditures Included in Current Liabilities as of December 31,	345	485		298.3
Appalachian Power Co [Member]
Operating Activites
NET INCOME (LOSS)	367.8	331.3		369.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	428.4	407.9		388.5
Deferred Income Taxes	(16.8)	171.5		130.7
Carrying Costs Income	(1.3)	(1.4)		(0.4)
Allowance for Equity Funds Used During Construction	(13.2)	(9.2)		(11.7)
Mark-to-Market of Risk Management Contracts	(33)	(23.1)		9.4
Pension Contributions to Qualified Plan Trust	0	(10.2)		(8.8)
Deferred Fuel Over/Under-Recovery, Net	(10.8)	(20.5)		22.2
Change in Other Noncurrent Assets	59.4	12.8		3.4
Change in Other Noncurrent Liabilities	(4.8)	11.9		(26.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	33.6	(28)		(48)
Fuel, Materials and Supplies	27.8	22.3		12.9
Accounts Payable	(13.3)	37.5		19.5
Accrued Taxes, Net	(13.2)	(12.7)		53.7
Other Current Assets	(6.1)	0.7		(9.8)
Other Current Liabilities	42.1	(10.8)		(9.9)
Net Cash Flows from (Used for) Operating Activities	846.6	880		894.7
Investing Activities
Construction Expenditures	(780.7)	(818.1)		(646.7)
Change in Advances to Affiliates, Net	0.5	0.6		1.5
Other Investing Activities	10.8	15.2		13.3
Net Cash Flows from (Used for) Investing Activities	(769.4)	(802.3)		(631.9)
Financing Activities
Issuance of Long-term Debt	203.2	320.9		314
Change in Advances from Affiliates, Net	19.6	106.4		(101.4)
Retirement of Long-term Debt	(124)	(377.9)		(213.6)
Principal Payments for Capital Lease Obligations	(6.9)	(6.9)		(6.4)
Dividends Paid on Common Stock	(160)	(120)		(255)
Other Financing Activities	1.5	0.5		0.5
Net Cash Flows from (Used for) Financing Activities	(66.6)	(77)		(261.9)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	10.6	0.7		0.9
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	19.2	18.5		17.6
Cash and Cash Equivalents at Beginning of Period	2.9
Cash, Cash Equivalents and Restricted Cash at End of Period	29.8	19.2		18.5
Cash and Cash Equivalents at End of Period	4.2	2.9
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	182	183.6		181.8
Net Cash Paid (Received) for Income Taxes	(13)	31.2		22.1
Noncash Acquisitions Under Capital Leases	5.5	3.5		6.1
Construction Expenditures Included in Current Liabilities as of December 31,	134.4	126.3		151.6
Indiana Michigan Power Co [Member]
Operating Activites
NET INCOME (LOSS)	261.3	186.7		239.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	293.1	210.9		191.7
Deferred Income Taxes	(42.9)	200.7		105.1
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	29.2	8.5		(48.4)
Asset Impairments and Other Related Charges	0	0		10.5
Carrying Costs Income	(3.9)	(12.7)		(10.1)
Allowance for Equity Funds Used During Construction	(11.9)	(11.1)		(15.3)
Mark-to-Market of Risk Management Contracts	(4.1)	(2.3)		2
Amortization of Nuclear Fuel	113.8	129.1		128.6
Pension Contributions to Qualified Plan Trust	0	(13)		(12.7)
Deferred Fuel Over/Under-Recovery, Net	39.7	13.7		(14.8)
Disposition of Tanners Creek Plant Site	0	0		(93.5)
Change in Other Noncurrent Assets	(32.6)	(88.4)		(56.4)
Change in Other Noncurrent Liabilities	72.1	37.4		58.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	4.8	(1.1)		0.5
Fuel, Materials and Supplies	(11.2)	(7.5)		20.9
Accounts Payable	(14.1)	17.6		11.6
Accrued Taxes, Net	41.2	(16.6)		6
Other Current Assets	1.5	14.5		8
Other Current Liabilities	(10.3)	(5.1)		(2.1)
Net Cash Flows from (Used for) Operating Activities	725.7	661.3		529.7
Investing Activities
Construction Expenditures	(568.5)	(648.5)		(596.9)
Change in Advances to Affiliates, Net	(0.3)	0.1		(0.8)
Purchases of Investment Securities	(2,064.7)	(2,300.5)		(3,000)
Sales of Investment Securities	2,010	2,256.3		2,957.7
Acquisitions of Nuclear Fuel	(46.1)	(108)		(128.5)
Other Investing Activities	14.8	9.7		8.4
Net Cash Flows from (Used for) Investing Activities	(654.8)	(790.9)		(760.1)
Financing Activities
Issuance of Long-term Debt	1,168.1	530.1		569.4
Change in Advances from Affiliates, Net	(210.5)	(3.6)		(79.1)
Retirement of Long-term Debt	(884.9)	(260.7)		(100.2)
Principal Payments for Capital Lease Obligations	(8.8)	(12)		(35.3)
Dividends Paid on Common Stock	(124.7)	(125)		(125)
Other Financing Activities	(9)	0.9		0.7
Net Cash Flows from (Used for) Financing Activities	(69.8)	129.7		230.5
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	1.1	0.1		0.1
Cash and Cash Equivalents at Beginning of Period	1.3	1.2		1.1
Cash and Cash Equivalents at End of Period	2.4	1.3		1.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	116.9	94.8		83.3
Net Cash Paid (Received) for Income Taxes	32.6	(89.9)		(39.5)
Noncash Acquisitions Under Capital Leases	5.8	7.1		18.2
Construction Expenditures Included in Current Liabilities as of December 31,	93	88.5		106.2
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	4	0		2.1
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	2.2	2.6		0.7
Ohio Power Co [Member]
Operating Activites
NET INCOME (LOSS)	325.5	323.9		282.2
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	259.7	225.9		238.6
Generation Deferrals	0	0		(82.7)
Amortization of Generation Deferrals	223.9	229.2		242.9
Deferred Income Taxes	(36.2)	147.9		(39.2)
Carrying Costs Income	(1.7)	(3.6)		(19.9)
Allowance for Equity Funds Used During Construction	(9.8)	(6.4)		(6)
Mark-to-Market of Risk Management Contracts	(32.2)	13		134.6
Pension Contributions to Qualified Plan Trust	0	(8.2)		(7.1)
Property Taxes	(12.5)	(17.9)		(9.8)
Provision for Refund - Global Settlement	(5.5)	(98.2)		120.3
Change in Regulatory Assets	171.5	(70.7)		(139.8)
Change in Other Noncurrent Assets	(9.8)	(51.1)		(44.6)
Change in Other Noncurrent Liabilities	53.8	15.8		31
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	43.1	(30.1)		(26.6)
Fuel, Materials and Supplies	(11.3)	(11.1)		(2.1)
Accounts Payable	(13.8)	11.6		13.7
Accrued Taxes, Net	26.8	(9.4)		(6)
Other Current Assets	8.1	(9.2)		0
Other Current Liabilities	49.1	(29.2)		(33.2)
Net Cash Flows from (Used for) Operating Activities	1,028.7	622.2		646.3
Investing Activities
Construction Expenditures	(725.9)	(567.7)		(416.2)
Change in Advances to Affiliates, Net	0	24.2		306.9
Other Investing Activities	18.4	12.6		12
Net Cash Flows from (Used for) Investing Activities	(707.5)	(530.9)		(97.3)
Financing Activities
Issuance of Long-term Debt	392.8	0		0
Change in Advances from Affiliates, Net	26.3	87.8		0
Retirement of Long-term Debt	(397.1)	(46.4)		(395.9)
Principal Payments for Capital Lease Obligations	(3.8)	(4.1)		(4.2)
Dividends Paid on Common Stock	(337.5)	(130)		(150)
Other Financing Activities	0.9	0.8		0.6
Net Cash Flows from (Used for) Financing Activities	(318.4)	(91.9)		(549.5)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	2.8	(0.6)		(0.5)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	29.7	30.3		30.8
Cash and Cash Equivalents at Beginning of Period	3.1
Cash, Cash Equivalents and Restricted Cash at End of Period	32.5	29.7		30.3
Cash and Cash Equivalents at End of Period	4.9	3.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	97.1	100		109.9
Net Cash Paid (Received) for Income Taxes	51.3	48.5		220.4
Noncash Acquisitions Under Capital Leases	4.4	4.5		3.4
Construction Expenditures Included in Current Liabilities as of December 31,	98.2	87.8		44.6
Public Service Co Of Oklahoma [Member]
Operating Activites
NET INCOME (LOSS)	83.2	72		100
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	164	130.4		130.2
Deferred Income Taxes	(31.1)	124.7		82.5
Allowance for Equity Funds Used During Construction	(0.4)	(0.5)		(6.2)
Mark-to-Market of Risk Management Contracts	(3)	(5.6)		(0.4)
Pension Contributions to Qualified Plan Trust	0	(5.3)		(5.6)
Deferred Fuel Over/Under-Recovery, Net	57.4	(5.4)		(109.9)
Provision for Refund	3.8	(43.5)		46.1
Change in Other Noncurrent Assets	0	(27.2)		(35.9)
Change in Other Noncurrent Liabilities	17.6	4.5		(0.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	5.1	(10.9)		(9)
Fuel, Materials and Supplies	(2.6)	13		2
Accounts Payable	17.7	(10.7)		25.7
Accrued Taxes, Net	13.2	0.8		7.4
Other Current Assets	(0.8)	(2.1)		0.8
Other Current Liabilities	6.4	3.9		(10.4)
Net Cash Flows from (Used for) Operating Activities	330.5	238.1		217.2
Investing Activities
Construction Expenditures	(240.2)	(266.1)		(351.1)
Change in Advances to Affiliates, Net	0	0		80.6
Other Investing Activities	7.2	4.6		11
Net Cash Flows from (Used for) Investing Activities	(233)	(261.5)		(259.5)
Financing Activities
Issuance of Long-term Debt	0	0		274.2
Change in Advances from Affiliates, Net	(44.1)	97.6		52
Retirement of Long-term Debt	(0.5)	(0.5)		(275.4)
Dividends Paid on Common Stock	(50)	(70)		(5)
Other Financing Activities	(2.5)	(3.6)		(3.4)
Net Cash Flows from (Used for) Financing Activities	(97.1)	23.5		42.4
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	0.4	0.1		0.1
Cash and Cash Equivalents at Beginning of Period	1.6	1.5		1.4
Cash and Cash Equivalents at End of Period	2	1.6		1.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	62	61.5		60.1
Net Cash Paid (Received) for Income Taxes	17.9	(72.6)		(37.7)
Noncash Acquisitions Under Capital Leases	4.3	2.1		3.1
Construction Expenditures Included in Current Liabilities as of December 31,	33.2	23.1		33.6
Southwestern Electric Power Co [Member]
Operating Activites
NET INCOME (LOSS)	152.2	137.5		169.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	239.5	217.4		196.5
Deferred Income Taxes	1.2	80.5		162.6
Asset Impairments and Other Related Charges	0	33.6		0
Allowance for Equity Funds Used During Construction	(6)	(2.4)		(11)
Mark-to-Market of Risk Management Contracts	4	(5.6)		(5.1)
Pension Contributions to Qualified Plan Trust	0	(8.9)		(8.3)
Deferred Fuel Over/Under-Recovery, Net	(2.4)	(0.8)		(8.9)
Change in Regulatory Liabilities	(3.8)	(12.3)		(22)
Change in Other Noncurrent Assets	(18.8)	(9.2)		(13)
Change in Other Noncurrent Liabilities	46.6	17		6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	53.5	(32.9)		(5.7)
Fuel, Materials and Supplies	3.5	(16)		38.1
Accounts Payable	0.9	10.5		3.5
Accrued Taxes, Net	2.3	45.7		(68.9)
Other Current Assets	15.6	5.2		(13.9)
Other Current Liabilities	16.5	(14.6)		(15.3)
Net Cash Flows from (Used for) Operating Activities	504.8	444.7		404.3
Investing Activities
Construction Expenditures	(451)	(404.1)		(426.3)
Change in Advances to Affiliates, Net	(81.4)	167.8		(167.8)
Proceeds from Sales of Assets	1.4	12.6		1.1
Other Investing Activities	2.1	3.1		(1)
Net Cash Flows from (Used for) Investing Activities	(528.9)	(220.6)		(594)
Financing Activities
Issuance of Long-term Debt	1,065.7	114.6		406.7
Change in Short-term Debt, Net	(22)	22		0
Change in Advances from Affiliates, Net	(118.7)	118.7		(58.3)
Retirement of Long-term Debt	(794.5)	(353.7)		(3.3)
Principal Payments for Capital Lease Obligations	(11.5)	(11.3)		(27.1)
Dividends Paid on Common Stock	(65)	(110)		(120)
Dividends Paid on Common Stock	(4.3)	(13.6)		(4.2)
Other Financing Activities	(2.7)	0.5		1
Net Cash Flows from (Used for) Financing Activities	47	(232.8)		194.8
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net Increase (Decrease) in Cash and Cash Equivalents	22.9	(8.7)		5.1
Cash and Cash Equivalents at Beginning of Period	1.6	10.3		5.2
Cash and Cash Equivalents at End of Period	24.5	1.6		10.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	125.7	124.4		118
Net Cash Paid (Received) for Income Taxes	18.8	(75.3)		(32)
Noncash Acquisitions Under Capital Leases	3.6	3.3		5.9
Construction Expenditures Included in Current Liabilities as of December 31,	$ 42	$ 71.2		$ 41.8
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[3]	(a)Reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see “Revisions to Previously Issued Financial Statements” below.
[4]	The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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. 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 AEPTCo’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 (consolidated VIEs). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a consolidated VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated 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 on 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. 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, 2018 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 234.1 $ 3.1 $ 4.2 $ 4.9 Restricted Cash 210.0 156.7 25.6 27.6 Total Cash, Cash Equivalents and Restricted Cash $ 444.1 $ 159.8 $ 29.8 $ 32.5 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 Other Temporary Investments (Applies to AEP) Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. 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 over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, 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 transactions with REPs 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, TXU Energy and Reliant Energy 2018 (b) 2017 (a)(b) 2016 (a) Percentage of Total Revenues 45 % 35 % 46 % Percentage of Accounts Receivable – Customers 35 % 31 % 42 % (a) TXU Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer. (b) 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 2018 2017 2016 Percentage of Total Revenues 77 % 80 % 77 % Percentage of Total Accounts Receivable 84 % 85 % (a) 86 % (a) Reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous 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 on the Registrant Subsidiaries’ statements of income 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 sheets. 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. 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 equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value. 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 using 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 commission-approved plan to delay refunds or recoveries beyond a one year period. 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 SSO 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 incurred from 2009 through 2011, that continued to be recovered in rider rates were terminated in January 2019. 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 or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income. Retail and Wholesale Supply and Delivery of Electricity The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by the Registrants in the second quarter following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - 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. See Note 20 - Revenue from Contracts with Customers for additional information related to retail and wholesale revenues. Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities 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 b

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements	2 . 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 with a customer, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Management adopted ASU 2014-09 effective January 1, 2018, by means of the modified retrospective approach for all contracts within the scope of the new standard. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. In that regard, the application of the new standard did not cause any significant differences in any individual financial statement line items had those line items been presented in accordance with the guidance that was in effect prior to the adoption of the new standard. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in the Registrants’ previously established accounting policies for revenue. See Note 20 - Revenue from Contracts with Customers for additional disclosures required by the new standard. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 revising the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in an immaterial impact to the results of operations and financial position of AEP, and no impact to the 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 terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. New leasing standard implementation activities included the identification of the lease population within the AEP System as well as the sampling of representative lease contracts to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a gap analysis to outline new disclosure compliance requirements. Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheet. Management elected the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Existing and expired land easements not previously accounted for as leases Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. Cumulative-effect adjustment in the period of adoption Elect the optional transition practical expedient to adopt the new lease requirements through a cumulative-effect adjustment on the balance sheet in the period of adoption. Management concluded that the result of adoption would not materially change the volume of contracts that qualify as leases going forward. The adoption of the new standard did not materially impact results of operations or cash flows, but did have a material impact on the balance sheet. The impact to the balance sheet has been estimated for the first quarter of 2019 as shown in the table below. Company Estimated Obligation (in millions) AEP $ 1,070.4 AEP Texas 80.2 AEPTCo 5.4 APCo 80.4 I&M 351.1 OPCo 76.8 PSO 32.2 SWEPCo 35.8 ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 and related implementation guidance effective January 1, 2020. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component is eligible for capitalization as applicable following labor. Management adopted ASU 2017-07 effective January 1, 2018. Presentation of the non-service components on a separate line outside of operating income was applied on a retrospective basis, using the amounts disclosed in the benefit plan note for the estimation basis as a practical expedient. Capitalization of only the service cost component was applied on a prospective basis. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives of the new standard are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and to reduce the complexity of applying hedge accounting. Among other things, ASU 2017-12: (a) expands the types of transactions eligible for hedge accounting, (b) eliminates the separate measurement and presentation of hedge ineffectiveness, (c) simplifies the requirements for assessments of hedge effectiveness, (d) provides companies more time to finalize hedge documentation and (e) enhances presentation and disclosure requirements. Management early adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018, by means of a modified retrospective approach. The adoption of ASU 2017-12 resulted in an immaterial impact to the 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. The adoption of the new standard did not give rise to any material changes to the Registrants’ previously established accounting policies for derivatives and hedging. ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02) In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. The accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be adjusted for the effect of a change in tax law or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date of the tax change. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI would not reflect the newly enacted corporate tax rate. Management adopted ASU 2018-02 effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. A portion of the reclassification was recorded to Regulatory Liabilities to adjust the tax effects of certain interest rate hedges in AEP's regulated jurisdictions that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement of financial position and did not impact results of operations or cash flows. ASU 2018-14 “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans” (ASU 2018-14) In August 2018, the FASB issued ASU 2018-14 modifying the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments in this Update to Subtopic 715-20 remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures and add disclosure requirements identified as relevant. Management early adopted ASU 2018-14 for the 2018 Annual Report and applied the new standard retrospectively for all periods presented. As a result of adoption, the Registrants’ disclosures were updated as follows: • Amended the disclosure to remove the amounts in AOCI expected to be recognized as components of net periodic benefit cost over the next fiscal year. • Amended the disclosure to remove the effects of a one-percentage-point change in assumed health care cost trend rates on the (a) aggregate of the service and interest cost components of net periodic benefit costs and (b) benefit obligation for postretirement health care benefits. • Amended the disclosure to include the weighted-average interest crediting rates for cash balance plans and other plans with promised interest crediting rates. • Amended the disclosure to include an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. See Note 8 - Benefit Plans for updates to the disclosures required by the new standard. ASU 2018-15 “Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” (ASU 2018-15) In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. To eliminate diversity in practice, the new standard changes the presentation of implementation costs for cloud service arrangements that are service contracts without the purchase of a license. Implementation costs for cloud service contracts will be presented on the balance sheets in the same manner as a prepayment. The Registrants currently present implementation costs in property, plant and equipment on the balance sheets. Under the new standard, amortization of capitalized implementation costs of a hosting arrangement will be recorded in Operation and Maintenance expense over the term of the cloud service arrangement, rather than Depreciation and Amortization expense on the statements of income. Payments for capitalized implementation costs in the statement of cash flows will be classified in the same manner as payments made for fees associated with the hosting element. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The amendments may be applied either retrospectively or prospectively to applicable implementation costs incurred after the date of adoption. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2018-15 prospectively, effective January 1, 2020.

Comprehensive Income

Comprehensive Income	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 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, 2017 $ (28.4 ) $ (13.0 ) $ 11.9 $ 141.6 $ (179.9 ) $ (67.8 ) Change in Fair Value Recognized in AOCI 37.3 2.3 — — (33.0 ) 6.6 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — — — (0.1 ) Purchased Electricity for Resale (a) (32.6 ) — — — — (32.6 ) Interest Expense (a) — 1.1 — — — 1.1 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains) Losses — — — 12.8 — 12.8 Reclassifications from AOCI, before Income Tax (Expense) Benefit (32.7 ) 1.1 — (6.7 ) — (38.3 ) Income Tax (Expense) Benefit (6.9 ) 0.3 — (1.4 ) — (8.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (25.8 ) 0.8 — (5.3 ) — (30.3 ) Net Current Period Other Comprehensive Income (Loss) 11.5 3.1 — (5.3 ) (33.0 ) (23.7 ) ASU 2018-02 Adoption (b) (6.1 ) (2.7 ) — — (8.2 ) (17.0 ) ASU 2016-01 Adoption (b) — — (11.9 ) — — (11.9 ) Balance in AOCI as of December 31, 2018 $ (23.0 ) $ (12.6 ) $ — $ 136.3 $ (221.1 ) $ (120.4 ) 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 (a) (5.6 ) — — — — (5.6 ) Purchased Electricity for Resale (a) 28.8 — — — — 28.8 Interest Expense (a) — 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) Benefit 23.2 1.5 — 1.7 — 26.4 Income Tax (Expense) Benefit 8.1 0.4 — 0.6 — 9.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 (a) (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale (a) 16.4 — — — — 16.4 Interest Expense (a) — 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) Benefit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Benefit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2017 $ (4.5 ) $ 4.5 $ (12.6 ) $ (12.6 ) Change in Fair Value Recognized in AOCI — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains) Losses — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.3 0.3 — 1.6 Income Tax (Expense) Benefit 0.3 0.1 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.0 0.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.0 0.2 (1.0 ) 0.2 ASU 2018-02 Adoption (b) (0.9 ) — (1.8 ) (2.7 ) Balance in AOCI as of December 31, 2018 $ (4.4 ) $ 4.7 $ (15.4 ) $ (15.1 ) 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 (a) 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains) Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.3 0.4 — 1.7 Income Tax (Expense) Benefit 0.4 0.1 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.9 0.3 — 1.2 Net Current Period Other Comprehensive Income (Loss) 0.9 0.3 1.1 2.3 Balance in AOCI as of December 31, 2017 $ (4.5 ) $ 4.5 $ (12.6 ) $ (12.6 ) 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 (a) 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) Benefit 1.8 0.4 — 2.2 Income Tax (Expense) Benefit 0.6 0.1 — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2017 $ — $ 2.2 $ 14.8 $ (15.7 ) $ 1.3 Change in Fair Value Recognized in AOCI (0.7 ) — — (2.6 ) (3.3 ) Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (a) 0.9 — — — 0.9 Interest Expense (a) — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.2 ) — (5.2 ) Amortization of Actuarial (Gains) Losses — — 1.3 — 1.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.9 (1.1 ) (3.9 ) — (4.1 ) Income Tax (Expense) Benefit 0.2 (0.2 ) (0.8 ) — (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.7 (0.9 ) (3.1 ) — (3.3 ) Net Current Period Other Comprehensive Income (Loss) — (0.9 ) (3.1 ) (2.6 ) (6.6 ) ASU 2018-02 Adoption (b) — 0.5 — (0.2 ) 0.3 Balance in AOCI as of December 31, 2018 $ — $ 1.8 $ 11.7 $ (18.5 ) $ (5.0 ) 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 (a) (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) Benefit (1.1 ) (1.8 ) — (2.9 ) Income Tax (Expense) Benefit (0.4 ) (0.6 ) — (1.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 (a) (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) Benefit (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Benefit (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2017 $ (10.7 ) $ 5.1 $ (6.5 ) $ (12.1 ) Change in Fair Value Recognized in AOCI — — (0.6 ) (0.6 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 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) Benefit 2.0 — — 2.0 Income Tax (Expense) Benefit 0.4 — — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 — — 1.6 Net Current Period Other Comprehensive Income (Loss) 1.6 — (0.6 ) 1.0 ASU 2018-02 Adoption (b) (2.4 ) — (0.3 ) (2.7 ) Balance in AOCI as of December 31, 2018 $ (11.5 ) $ 5.1 $ (7.4 ) $ (13.8 ) 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 (a) 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) Benefit 2.0 — — 2.0 Income Tax (Expense) Benefit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 (a) 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) Benefit 2.0 — — 2.0 Income Tax (Expense) Benefit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 1.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.7 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.7 ) Income Tax (Expense) Benefit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) ASU 2018-02 Adoption (b) 0.4 Balance in AOCI as of December 31, 2018 $ 1.0 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 (a) (1.7 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.7 ) Income Tax (Expense) Benefit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 (a) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.9 ) Income Tax (Expense) Benefit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) Balance in AOCI as of December 31, 2016 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 2.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3 ) Income Tax (Expense) Benefit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0 ) Net Current Period Other Comprehensive Income (Loss) (1.0 ) ASU 2018-02 Adoption (b) 0.5 Balance in AOCI as of December 31, 2018 $ 2.1 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 (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3 ) Income Tax (Expense) Benefit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 (a) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.2 ) Income Tax (Expense) Benefit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2016 $ 3.4 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 1.2 $ 0.8 $ (4.0 ) Change in Fair Value Recognized in AOCI 2.3 — (3.1 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 2.1 — — 2.1 Amortization of Prior Service Cost (Credit) — (2.0 ) — (2.0 ) Amortization of Actuarial (Gains) Losses — 0.2 — 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.1 (1.8 ) — 0.3 Income Tax (Expense) Benefit 0.4 (0.4 ) — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.7 (1.4 ) — 0.3 Net Current Period Other Comprehensive Income (Loss) 4.0 (1.4 ) (3.1 ) (0.5 ) ASU 2018-02 Adoption (b) (1.3 ) — 0.4 (0.9 ) Balance in AOCI as of December 31, 2018 $ (3.3 ) $ (0.2 ) $ (1.9 ) $ (5.4 ) 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 (a) 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) Benefit 2.2 (1.1 ) — 1.1 Income Tax (Expense) Benefit 0.8 (0.4 ) — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 (a) 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) Benefit 2.7 (1.1 ) — 1.6 Income Tax (Expense) Benefit 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 ) (a) Amounts reclassified to the referenced line item on the statements of income. (b) See Note 2 - New Accounting Pronouncements for additional information.

Rate Matters

Rate Matters	12 Months Ended
	Dec. 31, 2018
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 impacts outstanding rate and regulatory matters. For additional 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, 2018 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2018, subject to review, are estimated to be $1 billion . A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019. In 2018, the PUCT issued approvals to increase AEP Texas’ transmission rates by $22 million annually. The approvals included an increase in annual revenues to recover transmission capital additions of $46 million offset by a reduction in annual revenues of $24 million due to the reduction in the federal income tax rate due to Tax Reform. The approvals did not address the return of Excess ADIT benefits to customers. In August 2018, the PUCT approved a Stipulation and Settlement agreement to amend AEP Texas’ Distribution Cost Recovery Factor to reduce annual distribution rates by approximately $24 million annually, beginning September 1, 2018. The settlement included an increase in annual revenues to recover 2017 distribution capital additions of $19 million offset by reductions in annual revenues of: (a) $21 million due to the reduction in the federal income tax rate due to Tax Reform, (b) $10 million due to Excess ADIT associated with certain depreciable property to be amortized using ARAM and (c) $12 million due to Excess ADIT that is not subject to rate normalization requirements to be refunded over 5 years. Hurricane Harvey and Texas Storm Cost Securitization In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of December 31, 2018 , the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $152 million , inclusive of approximately $129 million of incremental storm expenses related to Hurricane Harvey. See the table below for additional information on the Hurricane Harvey storm restoration costs: December 31, 2018 Total Hurricane Harvey Storm Costs Capital O&M Regulatory Asset Total (in millions) Restoration Costs Incurred $ 219.1 $ 136.9 $ — $ 356.0 Incremental Operation and Maintenance Expenses (O&M) — (129.8 ) 129.8 — Insurance Proceeds (12.7 ) — (1.2 ) (13.9 ) Total Hurricane Harvey Storm Costs, Net $ 206.4 $ 7.1 $ 128.6 $ 342.1 The securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018, AEP Texas filed a Determination of System Restoration Costs (DSRC) with the PUCT for total estimated storm costs in the amount of $425 million , which includes estimated carrying costs. The total estimated storm costs net of insurance proceeds, tax credits received for the Disaster Tax Relief and Airport and Airway Extension Act of 2017, and Excess ADIT that is not subject to rate normalization requirements utilized to reduce the non-capital Hurricane Harvey costs is $370 million . In November 2018, AEP Texas, the PUCT staff and intervenors filed a stipulation and settlement agreement with the PUCT that included all aspects of the DSRC filing with the following exceptions: (a) a $5 million permanent storm restoration reduction, (b) a $4 million disallowance of charges not directly related to storm restoration that will be included in a future regulatory proceeding and (c) a $5 million disallowance due to additional insurance proceeds received. See the table below for a reconciliation of the filed Determination of System Restoration Costs and settlement and stipulation agreement: Total Estimated Storm Costs Requested in the DSRC December 31, 2018 (in millions) Total Estimated Hurricane Harvey Storm Costs $ 356.0 Estimated Hurricane Harvey Carrying Costs 31.5 Estimated Litigation Costs 0.6 Non-Hurricane Harvey Storm Restoration Costs 36.5 Total Estimated Storm Costs requested in the DSRC 424.6 less: Tax Credit (0.8 ) Insurance Proceeds (8.7 ) Excess ADIT (a) (45.5 ) Total Estimated Storm Costs requested in the DSRC, after adjustments 369.6 less: Settlement Agreement Adjustments (10.6 ) Incremental Insurance Proceeds Received (5.1 ) Total Estimated Storm Costs per Settlement Agreement $ 353.9 (a) Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements. AEP Texas will seek to securitize estimated distribution related assets of $247 million in the first half of 2019 while the remaining $107 million of estimated transmission related assets is expected to be recovered through interim transmission filings or an upcoming base rate case. If these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Earnings 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 were frozen until after the Virginia SCC ruled on APCo’s next biennial review. These amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that: (a) on a one-time basis, required APCo to exclude $10 million of incurred fuel expenses from the July 2018 over/under recovery calculation, (b) reduced APCo’s base rates by $50 million annually effective July 30, 2018, on an interim basis and subject to true-up, to reflect the reduction in the federal income tax rate due to Tax Reform, (c) will require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) will 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, (e) will require APCo to seek approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period ending July 1, 2028 and (f) will require APCo to construct and/or acquire solar generation facilities in Virginia, subject to approval of the Virginia SCC, of at least 200 MW of aggregate capacity by July 1, 2028. Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded, or may be offset by capital expenditures in Virginia SCC approved energy distribution grid transformation projects and/or new utility-owned solar and wind generation facilities. In November 2018, the Virginia SCC approved a return on common equity of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period and rate adjustment clauses from November 2018 through November 2020. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable but is reasonably possible that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period. The Virginia triennial review of APCo earnings could materially reduce future net income and cash flows and impact financial condition. Virginia Staff Depreciation Study Request In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense ( $6 million related to transmission) with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of the Virginia SCC’s upcoming Triennial Review of APCo, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review. If the Virginia SCC were to issue an order approving the Virginia staff’s recommended retroactive change in APCo’s Virginia depreciation rates, it would reduce future net income and cash flows and impact financial condition. Virginia Tax Reform In October 2018, the Virginia SCC issued an order approving APCo’s request to refund $55 million of Excess ADIT that is not subject to rate normalization requirements to customers through a rider. The rider is being paid over twelve months effective November 1, 2018 and will offset APCo’s recent increase in interim fuel rates, subject to refund, as approved by the Virginia SCC. In October 2018, APCo also submitted a filing with the Virginia SCC to resolve outstanding issues related to Tax Reform. The filing incorporated the $50 million being refunded to customers as disclosed in “Virginia Legislation Affecting Earnings Reviews” above and, if approved, will reduce APCo’s base rates by an additional $7 million annually. The combined reduction in APCo’s base rates due to Tax Reform will refund: (a) $39 million annually of excess federal income taxes collected since January 1, 2018 until new base rates are implemented, (b) $7 million annually of Excess ADIT associated with certain depreciable property using ARAM and (c) $11 million annually of Excess ADIT that is not subject to rate normalization requirements over 10 years. In November 2018, the Virginia SCC staff filed testimony recommending a total annual reduction in APCo’s base rates of $69 million . The proposed reduction consisted of: (a) $41 million annually of excess federal income taxes collected since January 1, 2018 until new base rates are implemented, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM and (c) $19 million annually of Excess ADIT that is not subject to rate normalization requirements over 5 years. The Virginia SCC staff also recommended that APCo provide a one-time credit of $23 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019. Intervenors filed testimony recommending that the $23 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019 be refunded over 1 year and Excess ADIT that is not subject to rate normalization requirements be refunded over 3 years. In December 2018, APCo filed rebuttal testimony with the Virginia SCC generally agreeing with the Virginia SCC staff testimony. A hearing at the Virginia SCC was held in January 2019 where both APCo and the Virginia SCC staff lowered their reduction for excess federal income taxes collected since January 1, 2018 by $1 million . APCo anticipates a final order from the Virginia SCC by the end of the first quarter of 2019 and expects to implement additional customer rate credits in a tax-related rider starting in April 2019. The Virginia SCC’s review of APCo’s Tax Reform filing could reduce future net income and cash flows and impact financial condition. 2018 West Virginia Base Rate Case In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ( $98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase included $32 million ( $28 million related to APCo) due to increased annual depreciation expense and reflected the impact of the reduction in the federal income tax rate due to Tax Reform. In October 2018, APCo and WPCo filed updated schedules supporting a $95 million ( $80 million related to APCo) annual increase in West Virginia base rates primarily due to the impact of West Virginia Tax Reform case discussed below. In November 2018 APCo, WPCo, WVPSC staff and certain intervenors filed a Stipulation and Settlement agreement with the WVPSC. The agreement included a proposed annual base rate increase of $44 million ( $36 million related to APCo) based upon a 9.75% return on common equity effective March 2019. The agreement provided for an annual increase of $18 million ( $14 million related to APCo) due to increased annual depreciation expense. Depreciation rates were decreased from the original request primarily due to continuing with a 2040 retirement date for Clinch River Plant rather than APCo’s proposed retirement date of 2025. The agreement also included: (a) a proposal to refund, through a rider, $24 million ( $19 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements over two years starting March 2019, (b) a proposal to utilize $14 million ( $12 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements to offset regulatory asset balances relating to ENEC, (c) an agreement to work with the WVPSC to establish economic incentive programs and (d) an agreement, barring any unforeseen events, to not initiate another base rate proceeding prior to April 1, 2020. An order from the WVPSC is expected in the first quarter 2019. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. West Virginia Tax Reform In August 2018, the WVPSC approved a settlement agreement between APCo, WPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform and provides refunds to customers, through a rider, effective September 1, 2018 of approximately $63 million ( $51 million related to APCo) through June 2020. In addition, per the agreement, APCo and WPCo utilized $139 million ( $125 million related to APCo) of current tax savings and Excess ADIT that is not subject to rate normalization requirements to offset regulatory asset balances related to carbon capture, storm damage, ENEC and vegetation management. The WVPSC order indicated that the remaining balance of Excess ADIT that is not subject to rate normalization requirements would be addressed at a later date. 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, 2018 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $884 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. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021. In June 2018, the PUCT approved ETT’s application to reduce its transmission rates by $28 million annually, beginning June 21, 2018, to reflect the reduction in the federal income tax rate due to Tax Reform. The filing did not address the return of Excess ADIT benefits to customers. In December 2018, the PUCT approved ETT’s request to refund $11 million of excess federal income taxes collected in 2018 prior to the reduction in transmission rates that were implemented on June 21, 2018. The refunds were completed in December 2018. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In 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. In February 2018, I&M filed a Stipulation and Settlement Agreement for a $97 million annual increase, based on a 9.95% return on equity, 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. In May 2018, the IURC issued an order approving the Stipulation and Settlement Agreement. 2017 Michigan Base Rate Case In 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. In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million , including an intervenor’s proposal for up to 10% of I&M’s Michigan retail customers to choose an alternate supplier for generation and a proposed capacity rate based on PJM’s net cost of new entry value of $289 /MW-day, as well as the MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8% . In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $50 million , effective April 2018 based on a 9.9% return on common equity. The MPSC also approved the ALJ’s recommendation related to the capacity rate. If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million . In October 2018, I&M filed a request with the MPSC seeking authority to defer costs related to customers choosing an alternate supplier starting in February 2019. In December 2018, the MPSC rejected I&M’s request. Michigan Tax Reform In August 2018, the MPSC approved I&M’s application to refund, through a rider, approximately $9 million annually for the impact of Tax Reform on I&M’s Michigan jurisdictional earnings effective September 1, 2018. In October 2018, I&M also made two filings with the MPSC recommending to: (a) refund $3 million over eight months for the impact of Tax Reform on Michigan jurisdictional earnings for the period April 26, 2018 through August 31, 2018, (b) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (c) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over 10 years. In January 2019, I&M received an order from the MPSC requiring I&M to refund $5 million over six months, effective February 2019, for the Michigan jurisdictional impacts of Tax Reform related to the period January 1, 2018 through August 31, 2018. An order from the MPSC regarding Excess ADIT is expected in the first half of 2019. Rockport Plant, Unit 2 SCR In 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. 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 and is expected to be placed in service in May 2020. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer and recover, through a rider, 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. In March 2018, the IURC issued an order approving: (a) the CPCN, (b) the $274 million estimated cost of the SCR, excluding AFUDC, (c) deferral of the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recovery of these costs using an I&M Indiana rider. Management intends to request recovery of the Michigan jurisdictional share of the SCR project in a future base rate case. If the Michigan jurisdictional share of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. The AEGCo ownership share of the SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In January 2018, the KPSC issued an order approving a 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 a total of $50 million of Rockport Plant UPA expenses for the years 2018 through 2022, with the manner and timing of 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 with rates effective no earlier than 2021 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. In June 2018, the KPSC issued an order approving an additional revenue increase of $765 thousand related to the calculation of federal income tax expense. This rate increase was effective June, 2018. Kentucky Tax Reform In June 2018, the KPSC issued an order approving a settlement agreement between KPCo and an intervenor that stipulates that KPCo will refund an estimated $82 million of Excess ADIT associated with certain depreciable property using ARAM and an estimated $93 million of Excess ADIT that is not subject to rate normalization requirements over 18 years. The refund was effective July 1, 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 revenue 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 2017, the PUCO rejected all pending rehearing requests related to the OVEC PPA. 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 June 2018, oral arguments were held before the Supreme Court of Ohio. In November 2018, the Ohio Supreme Court unanimously affirmed the PUCO’s order in the June 2015 - May 2018 ESP and PPA Rider cases. In 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. In 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 April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In May 2018, OPCo and various intervenors filed requests for rehearing with the PUCO. In June 2018, these requests for rehearing were approved to allow further consideration of the requests. In August 2018, the PUCO denied all requests for rehearing. In October 2018, an appeal was filed with the Ohio Supreme Court challenging various approved riders. If the Ohio Supreme Court reverses the PUCO’s decision, 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 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 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 in 2016. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers related to OPCo 2016 SEET earnings. 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. A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the first half of 2019. 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 negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition. Ohio Tax Reform In October 2018, the PUCO issued an order approving a September 2018 settlement agreement between OPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform. The settlement will: (a) refund excess federal income tax of $20 million annually, through a rider, effective January 1, 2018 until new base rates are implemented, (b) refund an estimated $278 million of Excess ADIT associated with depreciable property through OPCo’s DIR using ARAM, (c) utilize $48 million of Excess ADIT that is not subject to rate normalization to offset regulatory asset balances related to OPCo’s distribution decoupling program and (d) refund the remaining estimated $129 million of Excess ADIT that is not subject to rate normalization by December 31, 2024 through a rider beginning in the fourth quarter of 2018. PSO Rate Matters (Applies to AEP and PSO) 2018 Oklahoma Base Rate Case In October 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 10.3% return on common equity. PSO also proposed to implement a performance-based rate plan that combines a formula rate with a set of customer-focused performance incentive measures related to reliability, public safety, customer satisfaction and economic development. The proposed annual increase includes $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates includes the recovery of Oklaunion Power Station through 2028 (currently being recovered in rates through 2046). Management has announced plans to retire Oklaunion Power Station by October 2020. In January 2019, OCC staff and various intervenors filed testimony. OCC staff recommended a $57 million annual rate increase based on a 9% return on common equity while intervenor recommendations ranged from a decrease in rates of $6 million to an increase in rates of $34 million based on a return on common equity ranging from 9.3% to 9.36% , respectively. The difference between PSO’s requested annual base rate increase and the OCC staff and intervenors recommendations are primarily due to: (a) a reduction in the requested return on common equity, (b) a rejection to PSO’s request to increase depreciation rates, including the proposed accelerated recovery of the Oklaunion Power Station through 2028, (c) a disallowance of certain incentives and operation and maintenance expenses and (d) a proposal to refund Excess ADIT that is not subject to rate normalization requirements over 5 years instead of 10 years. In addition, certain parties recommended a debt only return on, or no recovery of, PSO’s estimated remaining net book value in the Oklaunion Power Station after its retirement, which is estimated to be $49 million . Also, a party recommended a potential refund of $9 million related to an SPP rider claiming that PSO did not

Effects of Regulation

Effects of Regulation	12 Months Ended
	Dec. 31, 2018
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Unit to be Retired by 2020 (Applies to AEP and PSO) In September 2018, management announced that the Oklaunion Power Station is probable of abandonment and is to be retired by October 2020. The table below summarizes the plant investment and cost of removal, currently being recovered, as well as the regulatory asset for accelerated depreciation for the generating unit as of December 31, 2018 . See “2018 Oklahoma Base Rate Case” section of Note 4 for additional information. Gross Investment Accumulated Depreciation Net Investment Accelerated Depreciation Regulatory Asset (a) Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (dollars in millions) $ 106.6 $ 62.8 $ 43.8 $ 5.5 $ 3.1 $ 5.0 2020 28 years (a) In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station. See “2018 Oklahoma Base Rate Case” section of Note 4 for additional information. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2018 2017 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 101.7 $ 203.1 1 year Under-recovered Fuel Costs - does not earn a return 48.4 89.4 1 year Total Current Regulatory Assets $ 150.1 $ 292.5 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 50.3 Kentucky Deferred Purchased Power Expenses 14.5 — Other Regulatory Assets Pending Final Regulatory Approval 14.8 9.6 Total Regulatory Assets Currently Earning a Return 79.6 59.9 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 152.4 128.0 Plant Retirement Costs - Asset Retirement Obligation Costs 35.3 39.7 Cook Plant Uprate Project — 36.3 Cook Plant Turbine — 15.9 Other Regulatory Assets Pending Final Regulatory Approval 20.7 42.2 Total Regulatory Assets Currently Not Earning a Return 208.4 262.1 Total Regulatory Assets Pending Final Regulatory Approval (b) 288.0 322.0 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 680.9 682.6 25 years Meter Replacement Costs 74.4 83.7 9 years Plant Retirement Costs - Asset Retirement Obligation Costs 64.3 34.3 22 years Ohio Capacity Deferral 57.8 172.6 1 year Advanced Metering System 45.3 33.5 2 years Environmental Control Projects 43.4 28.1 22 years Cook Plant Uprate Project 35.0 — 15 years Storm-Related Costs 31.1 39.3 4 years Mitchell Plant Transfer - West Virginia 17.0 17.8 22 years Deferred Cook Plant Life Cycle Management Project Costs - Michigan 16.1 — 16 years Cook Plant Turbine 15.8 — 20 years Ohio Distribution Decoupling 12.3 61.7 2 years Ohio Basic Transmission Cost Rider — 90.8 Other Regulatory Assets Approved for Recovery 46.1 49.4 various Total Regulatory Assets Currently Earning a Return 1,139.5 1,293.8 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,326.6 1,196.3 12 years Unamortized Loss on Reacquired Debt 134.2 129.9 30 years Unrealized Loss on Forward Commitments 104.6 139.3 14 years Cook Plant Nuclear Refueling Outage Levelization 37.5 66.7 3 years Postemployment Benefits 35.6 39.1 4 years Peak Demand Reduction/Energy Efficiency 31.9 40.1 8 years Medicare Subsidy 27.9 32.5 6 years Vegetation Management - West Virginia 26.6 33.5 3 years PJM/SPP Annual Formula Rate True Up 22.0 11.7 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 21.6 37.2 22 years PJM Costs and Off-system Sales Margin Sharing - Indiana 20.1 57.0 2 years Storm-Related Costs 11.3 44.2 5 years Virginia Transmission Rate Adjustment Clause — 32.6 Other Regulatory Assets Approved for Recovery 83.0 111.7 various Total Regulatory Assets Currently Not Earning a Return 1,882.9 1,971.8 Total Regulatory Assets Approved for Recovery 3,022.4 3,265.6 Total Noncurrent Regulatory Assets $ 3,310.4 $ 3,587.6 (a) As of December 31, 2018 , AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information. (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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. AEP December 31, Remaining 2018 2017 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 35.7 $ 8.7 1 year Over-recovered Fuel Costs - does not pay a return 22.9 3.2 1 year Total Current Regulatory Liabilities $ 58.6 $ 11.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ 0.2 $ 0.2 Total Regulatory Liabilities Currently Not Paying a Return 0.2 0.2 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 1,025.3 4,256.7 Excess ADIT that is Not Subject to Rate Normalization Requirements 695.0 1,378.0 Total Income Tax Related Regulatory Liabilities 1,720.3 5,634.7 Total Regulatory Liabilities Pending Final Regulatory Determination 1,720.5 5,634.9 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,742.8 2,637.1 (b) Ohio Basic Transmission Cost Rider 68.8 — 2 years Excess Earnings 8.9 9.4 35 years Deferred Investment Tax Credits 8.7 10.6 42 years Advanced Metering Infrastructure Surcharge 8.5 12.7 2 years Other Regulatory Liabilities Approved for Payment 0.4 1.3 various Total Regulatory Liabilities Currently Paying a Return 2,838.1 2,671.1 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 828.5 945.0 (c) Deferred Investment Tax Credits 204.9 191.2 44 years PJM Transmission Enhancement Refund 164.2 — 7 years Transition Charges - Texas 46.0 46.0 6 years Unrealized Gain on Forward Commitments 45.9 15.0 6 years Ohio Enhanced Service Reliability Plan 43.1 30.6 2 years Spent Nuclear Fuel 42.9 43.2 (c) Peak Demand Reduction/Energy Efficiency 17.5 25.6 3 years Other Regulatory Liabilities Approved for Payment 84.8 41.6 various Total Regulatory Liabilities Currently Not Paying a Return 1,477.8 1,338.2 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 2,925.7 — (d) Excess ADIT that is Not Subject to Rate Normalization Requirements 864.3 — 18 years Income Taxes Subject to Flow Through (1,286.1 ) (1,221.9 ) 56 years Total Income Tax Related Regulatory Liabilities 2,503.9 (1,221.9 ) Total Regulatory Liabilities Approved for Payment 6,819.8 2,787.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,540.3 $ 8,422.3 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. (d) Refunded using ARAM. AEP Texas December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) $ 152.4 $ 123.3 Rate Case Expense 0.2 0.1 Total Regulatory Assets Pending Final Regulatory Approval 152.6 123.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Advanced Metering System 45.3 33.5 2 years Meter Replacement Costs 40.1 44.9 9 years Total Regulatory Assets Currently Earning a Return 85.4 78.4 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 176.9 151.2 12 years Unamortized Loss on Reacquired Debt 6.0 7.7 19 years Transmission Cost Recovery Factor 1.7 9.5 2 years Other Regulatory Assets Approved for Recovery 7.4 8.5 various Total Regulatory Assets Currently Not Earning a Return 192.0 176.9 Total Regulatory Assets Approved for Recovery 277.4 255.3 Total Noncurrent Regulatory Assets $ 430.0 $ 378.7 (a) As of December 31, 2018 , AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information. AEP Texas December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 277.1 $ 578.3 Excess ADIT that is Not Subject to Rate Normalization Requirements 141.4 103.3 Total Regulatory Liabilities Pending Final Regulatory Determination 418.5 681.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 645.2 599.2 (b) Advanced Metering Infrastructure Surcharge 8.5 12.7 2 years Excess Earnings 6.3 6.8 13 years Total Regulatory Liabilities Currently Paying a Return 660.0 618.7 Regulatory Liabilities Currently Not Paying a Return Transition Charges - Texas 46.0 46.0 6 years Deferred Investment Tax Credits 10.8 12.3 44 years Other Regulatory Liabilities Approved for Payment — 0.6 various Total Regulatory Liabilities Currently Not Paying a Return 56.8 58.9 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 251.8 — (c) Income Taxes Subject to Flow Through (42.8 ) (38.7 ) 31 years Total Income Tax Related Regulatory Liabilities 209.0 (38.7 ) Total Regulatory Liabilities Approved for Payment 925.8 638.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,344.3 $ 1,320.5 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. AEPTCo December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Noncurrent Regulatory Assets Regulatory assets approved for recovery: Regulatory Assets Currently Not Earning a Return PJM/SPP Annual Formula Rate True Up $ 12.9 $ 11.7 2 years Total Regulatory Assets Approved for Recovery 12.9 11.7 Total Noncurrent Regulatory Assets $ 12.9 $ 11.7 AEPTCo December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Noncurrent Regulatory Liabilities Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 73.9 $ 512.8 Excess ADIT that is Not Subject to Rate Normalization Requirements 4.5 (20.6 ) Total Regulatory Liabilities Pending Final Regulatory Determination 78.4 492.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 99.5 66.7 (c) Total Regulatory Liabilities Currently Paying a Return 99.5 66.7 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 453.4 — (d) Excess ADIT that is Not Subject to Rate Normalization Requirements (28.5 ) — 10 years Income Taxes Subject to Flow Through (b) (81.5 ) (65.1 ) 52 years Total Income Tax Related Regulatory Liabilities 343.4 (65.1 ) Total Regulatory Liabilities Approved for Payment 442.9 1.6 Total Noncurrent Regulatory Liabilities $ 521.3 $ 493.8 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) The 2017 balance reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters. (c) Relieved as removal costs are incurred. (d) Refunded using ARAM. APCo December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Current Regulatory Assets Under-recovered Fuel Costs, Virginia - earns a return $ 82.4 $ 21.4 1 year Under-recovered Fuel Costs, West Virginia - does not earn a return 17.2 67.4 1 year Total Current Regulatory Assets $ 99.6 $ 88.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.0 $ 9.1 Total Regulatory Assets Currently Earning a Return 9.0 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 35.3 39.7 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Currently Not Earning a Return 35.9 40.3 Total Regulatory Assets Pending Final Regulatory Approval (a) 44.9 49.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.3 86.3 25 years West Virginia Delayed Customer Billing 0.6 7.8 1 year Other Regulatory Assets Approved for Recovery 0.6 3.9 various Total Regulatory Assets Currently Earning a Return 86.5 98.0 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 172.2 168.8 12 years Unamortized Loss on Reacquired Debt 89.3 93.2 27 years Vegetation Management Program - West Virginia 26.6 33.5 3 years Peak Demand Reduction/Energy Efficiency 19.7 18.1 8 years Postemployment Benefits 18.0 18.8 4 years Virginia Generation Rate Adjustment Clause 10.3 7.3 2 years Virginia Transmission Rate Adjustment Clause — 32.6 Storm-Related Costs - West Virginia — 32.2 Other Regulatory Assets Approved for Recovery 8.3 22.0 various Total Regulatory Assets Currently Not Earning a Return 344.4 426.5 Total Regulatory Assets Approved for Recovery 430.9 524.5 Total Noncurrent Regulatory Assets $ 475.8 $ 573.9 (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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 268.2 $ 794.4 Excess ADIT that is Not Subject to Rate Normalization Requirements 283.7 381.1 Total Regulatory Liabilities Pending Final Regulatory Determination 551.9 1,175.5 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 618.3 615.8 (b) Deferred Investment Tax Credits 1.0 0.9 42 years Total Regulatory Liabilities Currently Paying a Return 619.3 616.7 Regulatory Liabilities Currently Not Paying a Return PJM Transmission Enhancement Refund 47.7 — 7 years Unrealized Gain on Forward Commitments 34.7 9.5 6 years Virginia Transmission Rate Adjustment Clause 11.3 — 2 years Consumer Rate Relief - West Virginia 8.8 6.5 1 year Other Regulatory Liabilities Approved for Payment 3.9 1.9 various Total Regulatory Liabilities Currently Not Paying a Return 106.4 17.9 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 453.5 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 84.5 — 10 years Income Taxes Subject to Flow Through (365.9 ) (355.2 ) 26 years Total Income Tax Related Regulatory Liabilities 172.1 (355.2 ) Total Regulatory Liabilities Approved for Payment 897.8 279.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,449.7 $ 1,454.9 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. I&M December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 15.0 Total Current Regulatory Assets $ — $ 15.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ — $ 36.3 Cook Plant Turbine — 15.9 Deferred Cook Plant Life Cycle Management Project Costs - Michigan — 14.7 Rockport Plant Dry Sorbent Injection System - Indiana — 10.4 Other Regulatory Assets Pending Final Regulatory Approval 3.3 2.0 Total Regulatory Assets Pending Final Regulatory Approval 3.3 79.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 232.2 245.3 10 years Cook Plant Uprate Project 35.0 — 15 years Deferred Cook Plant Life Cycle Management Project Costs - Michigan 16.1 — 16 years Cook Plant Turbine 15.8 — 20 years Rockport Plant Dry Sorbent Injection System - Indiana 11.5 — 9 years Cook Plant, Unit 2 Baffle Bolts - Indiana 5.7 6.0 20 years Other Regulatory Assets Approved for Recovery 2.4 1.0 various Total Regulatory Assets Currently Earning a Return 318.7 252.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 84.9 77.8 12 years Cook Plant Nuclear Refueling Outage Levelization 37.5 66.7 3 years PJM Costs and Off-system Sales Margin Sharing - Indiana 20.1 57.0 2 years Unamortized Loss on Reacquired Debt 18.7 9.5 30 years Postemployment Benefits 6.5 9.7 4 years Medicare Subsidy 6.1 7.1 6 years Other Regulatory Assets Approved for Recovery 16.7 20.0 various Total Regulatory Assets Currently Not Earning a Return 190.5 247.8 Total Regulatory Assets Approved for Recovery 509.2 500.1 Total Noncurrent Regulatory Assets $ 512.5 $ 579.4 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs, Michigan - pays a return $ 4.5 $ — 1 year Over-recovered Fuel Costs, Indiana - does not pay a return 22.9 2.7 1 year Total Current Regulatory Liabilities $ 27.4 $ 2.7 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 125.0 $ 534.6 Excess ADIT that is Not Subject to Rate Normalization Requirements 40.6 193.0 Total Regulatory Liabilities Pending Final Regulatory Determination 165.6 727.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 182.5 202.2 (b) Total Regulatory Liabilities Currently Paying a Return 182.5 202.2 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 828.5 945.0 (c) Spent Nuclear Fuel 42.9 43.2 (c) Deferred Investment Tax Credits 29.4 34.1 21 years PJM Transmission Enhancement Refund 29.1 — 7 years Other Regulatory Liabilities Approved for Payment 24.0 11.5 various Total Regulatory Liabilities Currently Not Paying a Return 953.9 1,033.8 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 362.0 — (d) Excess ADIT that is Not Subject to Rate Normalization Requirements 192.6 — 10 years Income Taxes Subject to Flow Through (282.1 ) (254.9 ) 26 years Total Income Tax Related Regulatory Liabilities 272.5 (254.9 ) Total Regulatory Liabilities Approved for Payment 1,408.9 981.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,574.5 $ 1,708.7 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. (d) Refunded using ARAM. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return (a) $ 0.4 $ 115.9 1 year Total Current Regulatory Assets $ 0.4 $ 115.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 1.0 $ — Total Regulatory Assets Pending Final Regulatory Approval 1.0 — Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Ohio Capacity Deferral 57.8 172.6 1 year Ohio Distribution Decoupling 12.3 61.7 2 years Ohio Basic Transmission Cost Rider — 90.8 Other Regulatory Assets Approved for Recovery 0.9 1.7 various Total Regulatory Assets Currently Earning a Return 71.0 326.8 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 181.5 170.6 12 years Unrealized Loss on Forward Commitments 100.2 131.8 14 years Smart Grid Costs 8.1 — 2 years Postemployment Benefits 7.9 7.2 4 years Unamortized Loss on Reacquired Debt 6.5 7.8 20 years Other Regulatory Assets Approved for Recovery 11.3 8.6 various Total Regulatory Assets Currently Not Earning a Return 315.5 326.0 Total Regulatory Assets Approved for Recovery 386.5 652.8 Total Noncurrent Regulatory Assets $ 387.5 $ 652.8 (a) December 31, 2017 balance includes PIRR. OPCo December 31, Remaining Refund Period 2018 2017 Regulatory Liabilities: (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ 0.2 $ 0.2 Total Regulatory Liabilities Currently Not Paying a Return 0.2 0.2 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property — 436.3 Excess ADIT that is Not Subject to Rate Normalization Requirements — 230.8 Total Income Tax Related Regulatory Liabilities — 667.1 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 667.3 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 436.6 428.8 (b) Ohio Basic Transmission Cost Rider 68.8 — 2 years Other Regulatory Liabilities Approved for Payment 0.4 1.4 various Total Regulatory Liabilities Currently Paying a Return 505.8 430.2 Regulatory Liabilities Currently Not Paying a Return PJM Transmission Enhancement Refund 71.3 — 7 years Ohio Enhanced Service Reliability Plan 43.1 30.6 2 years Peak Demand Reduction/Energy Efficiency 14.9 23.6 2 years Distribution Investment Rider 7.8 0.3 2 years Other Regulatory Liabilities Approved for Payment 11.3 11.1 various Total Regulatory Liabilities Currently Not Paying a Return 148.4 65.6 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 350.5 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 279.1 — 10 years Income Taxes Subject to Flow Through (62.8 ) (62.9 ) 29 years Total Income Tax Related Regulatory Liabilities 566.8 (62.9 ) Total Regulatory Liabilities Approved for Payment 1,221.0 432.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,221.2 $ 1,100.2 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. PSO December 31, Remaining Recovery Period 2018 2017 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 36.7 Total Current Regulatory Assets $ — $ 36.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Oklaunion Power Station Accelerated Depreciation $ 5.5 $ — Total Regulatory Assets Currently Earning a Return 5.5 — Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval 0.5 3.3 Total Regulatory Assets Currently Not Earning a Return 0.5 3.3 Total Regulatory Assets Pending Final Regulatory Approval 6.0 3.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 153.4 138.5 22 years Meter Replacement Costs 34.3 38.8 9 years Storm-Related Costs 31.1 39.0 4 years Environmental Control Projects 29.2 28.1 22 years Red Rock Generating Facility 8.6 8.8 38 years Other Regulatory Assets Approved for Recovery 0.5 0.5 various Total Regulatory Assets Currently Earning a Return 257.1 253.7 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 84.3 72.7 12 years Peak Demand Reduction/Energy Efficiency 6.3 13.0 2 years Unamortized Loss on Reacquired Debt 4.3 5.0 14 years SPP Base Plan Fees 1.4 16.3 2 years Other Regulatory Assets Approved for Recovery 9.6 4.1 various Total Regulatory Assets Currently Not Earning a Return 105.9 111.1 Total Regulatory Assets Approved for Recovery 363.0 364.8 Total Noncurrent Regulatory Assets $ 369.0 $ 368.1 PSO December 31, Remaining Refund Period 2018 2017 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 20.1 $ — 1 year Total Current Regulatory Liabilities $ 20.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ — $ 447.7 Excess ADIT that is Not Subject to Rate Normalization Requirements — 92.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 539.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 276.8 268.8 (b) Total Regulatory Liabilities Currently Paying a Return 276.8 268.8 Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 51.5 50.7 26 years Other Regulatory Liabilities Approved for Payment 2.5 2.3 various Total Regulatory Liabilities Currently Not Paying a Return 54.0 53.0 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 415.2 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 126.4 — 10 years Income Taxes Subject to Flow Through (7.7 ) (8.1 ) 27 years Total Income Tax Related Regulatory Liabilities 533.9 (8.1 ) Total Regulatory Liabilities Approved for Payment 864.7 313.7 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 864.7 $ 853.5 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. SWEPCo December 31, Remaining Recovery Period 2018 2017 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs, Arkansas/Louisiana - earns a return $ 18.8 $ 14.1 1 year Total Current Regulatory Assets $ 18.8 $ 14.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 50.3 Other Regulatory Assets Pending Final Regulatory Approval 0.3 0.5 Total Regulatory Assets Currently Earning a Return 50.6 50.8 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation - Arkansas, Louisiana 5.3 4.0 Rate Case Expense - Texas 4.9 4.3 Shipe Road Transmission Project - FERC — 3.3 Other Regulatory Assets Pending Final Regulatory Approval 3.6 2.5 Total Regulatory Assets Currently Not Earning a Return 13.8 14.1 Total Regulatory Assets Pending Final Regulatory Approval 64.4 64.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Environmental Controls Projects 14.2 — 14 years Other Regulatory Assets Approved for Recovery 7.2 7.2 various Total Regulatory Assets Currently Earning a Return 21.4 7.2 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 108.4 101.0 12 years Plant Retirement Costs - Unrecovered Plant 17.1 17.6 23 years Unamortized Loss on Reacquired Debt 7.4 4.7 25 years Medicare Subsidy 3.2 3.7 6 years Environmental Controls Projects — 15.3 Other Regulatory Assets Approved for Recovery 8.9 6.2 various Total Regulatory Assets Currently Not Earning a Return 145.0 148.5 Total Regulatory Assets Approved for Recovery 166.4 155.7 Total Noncurrent Regulatory Assets $ 230.8 $ 220.6 SWEPCo December 31, Remaining Refund Period 2018 2017 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs, Texas - pays a return $ 11.1 $ 8.7 1 year Total Current Regulatory Liabilities $ 11.1 $ 8.7 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 280.1 $ 650.5 Excess ADIT that is Not Subject to Rate Normalization Requirements 26.9 62.7 Total Regulatory Liabilities Pending Final Regulatory Determination 307.0 713.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 437.8 424.5 (b) Other Regulatory Liabilities Approved for Payment 2.5 2.6 various Total Regulatory Liabilities Currently Paying a Return 440.3 427.1 Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 4.5 5.9 13 years Other Regulatory Liabilities Approved for Payment 4.9 7.5 various Total Regulatory Liabilities Currently Not Paying a Return 9.4 13.4 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 370.5 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 54.3 — 2 years Income Taxes Subject to Flow Through (258.5 ) (257.3 ) 31 years Total Income Tax Related Regulatory Liabilities 166.3 (257.3 ) Total Regulatory Liabilities Approved for Payment 616.0 183.2 Total Noncurrent Regulatory Liabilities and Deferred Investmen

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 2018
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, 2018 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 1,081.7 $ 1,020.7 $ 306.7 $ 135.0 $ 2,544.1 Energy and Capacity Purchase Contracts 239.7 463.6 324.3 1,337.2 2,364.8 Total $ 1,321.4 $ 1,484.3 $ 631.0 $ 1,472.2 $ 4,908.9 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 391.8 $ 390.1 $ 8.4 $ 0.5 $ 790.8 Energy and Capacity Purchase Contracts 37.0 72.0 74.0 317.7 500.7 Total $ 428.8 $ 462.1 $ 82.4 $ 318.2 $ 1,291.5 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 251.4 $ 293.1 $ 187.8 $ 83.8 $ 816.1 Energy and Capacity Purchase Contracts 126.8 264.0 166.4 322.3 879.5 Total $ 378.2 $ 557.1 $ 354.2 $ 406.1 $ 1,695.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 31.0 $ 59.2 $ 60.2 $ 338.6 $ 489.0 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 58.4 $ 69.7 $ 20.1 $ — $ 148.2 Energy and Capacity Purchase Contracts 93.0 182.2 75.3 226.2 576.7 Total $ 151.4 $ 251.9 $ 95.4 $ 226.2 $ 724.9 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 108.8 $ 132.1 $ 32.6 $ — $ 273.5 Energy and Capacity Purchase Contracts 33.4 62.4 50.2 125.8 271.8 Total $ 142.2 $ 194.5 $ 82.8 $ 125.8 $ 545.3 (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 $4 billion revolving credit facility due in June 2022, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2018 , no letters of credit were issued under the 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 issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $305 million . The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2018 were as follows: Company Amount Maturity (in millions) AEP $ 60.6 January 2019 to December 2019 AEP Texas (a) 2.8 January 2019 OPCo 0.6 September 2019 (a) In January 2019, the letter of credit was amended to $2.2 million and the maturity date was extended until January 2020. 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 $140 million . Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work. This guarantee ends upon depletion of reserves and completion of reclamation. The reserves are estimated to deplete in 2036 with reclamation completed by 2046 at an estimated cost of $107 million . Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation. As of December 31, 2018 , SWEPCo has collected $75 million through a rider for reclamation costs, of which $80 million was recorded in Asset Retirement Obligations, offset by $5 million recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. Sabine charges all of its costs to its only customer, SWEPCo, which recovers these costs through its fuel clauses. Guarantees of Equity Method Investees (Applies to AEP) In December 2016, 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, 2018 , 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, 2018 , 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 equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for additional information. 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 non-hazardous 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, 2018 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are 11 additional sites for which APCo, I&M, KPCo, 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 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. The remediation work was completed in 2018 in accordance with a plan approved by MDEQ with no significant effects on net income. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2018 , management’s estimates do not anticipate material clean-up costs for identified Superfund sites. 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 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. Decommissioning and Low-Level Waste Accumulation Disposal The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of Cook Plant. The most recent decommissioning cost study was performed in 2018. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2 billion in 2018 non-discounted dollars, with additional ongoing costs of $6 million per year for post decommissioning storage of SNF and an eventual cost of $37 million for the subsequent decommissioning of the SNF storage facility, also in 2018 non-discounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $8 million , $9 million and $9 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2018 and 2017 , the total decommissioning trust fund balances were $2.2 billion and $2.2 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) 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. Spent Nuclear Fuel 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 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 $0 . As of December 31, 2018 and 2017 , fees and related interest of $274 million and $269 million , respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $317 million and $312 million , respectively, to pay the fee were 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 delay in accepting SNF for permanent storage. Under the settlement agreement, I&M received $11 million , $22 million and $6 million in 2018 , 2017 and 2016 , 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, 2018 and 2017 , I&M deferred $8 million and $11 million , respectively, in Prepayments and Other Current Assets and $23 million and $5 million , respectively, in Deferred Charges and Other Noncurrent Assets on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal” section of Note 11 for additional information. Nuclear Insurance I&M carries nuclear property insurance of $2.7 billion to cover an incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by an extraordinary incident. Insurance coverage for a nonnuclear property incident at 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 $50 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 of $14.1 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 $276 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $41 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 $13.6 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 a 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 above for additional information. 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 the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would 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, refueling or retirement of the unit. 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. AEGCo and I&M sought and were granted dismissal of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. The U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims, and remanding the case for further proceedings. 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. Responsive and supplemental filings have been made by all parties. 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. In September 2018, the district court granted AEP’s unopposed motion to stay further proceedings regarding the consent decree to facilitate settlement discussions among the parties to the consent decree. See “Proposed Modification of the NSR Litigation Consent Decree” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information. 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.

Dispositions, Assets and Liabil

Dispositions, Assets and Liabilities Held for Sale and Impairments	12 Months Ended
	Dec. 31, 2018
Impairments, Disposition and Assets and Liabilities Held for Sale	DISPOSITIONS 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 and 2016. Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion , which was recorded in Investing Activities on the statements 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 statements 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 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. In 2018, the MPSC and IURC approved the recovery of the additional costs associated with the sale of Tanners Creek Plant over the remaining useful life of Rockport, Unit 1. 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 Desert Sky and Trent (collectively “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 year ended December 31, 2016 as shown in the following table: Year Ended December 31, 2016 (in millions) Revenue $ 18.2 Other Operation Expense 6.5 Maintenance Expense 3.4 Asset Impairment and Other Related Charges 72.7 Depreciation and Amortization Expense 9.8 Taxes Other Than Income Taxes 1.3 Total Expenses 93.7 Other Income (Expense) (0.8 ) Pretax Loss of Discontinued Operations (76.3 ) Income Tax Benefit (27.5 ) Total Loss on Discontinued Operations as Presented on the Statements of Income $ (48.8 ) IMPAIRMENTS 2018 Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Applies to AEP and APCo) In the first quarter of 2018, AEP was notified by an equity investee that it had ceased operations. AEP recorded a pretax impairment of $21 million in Other Operation on the statements of income related to the equity investment and related assets. The impairment also had an immaterial impact to APCo. Merchant Generating Assets (Generation & Marketing Segment) A project to reconstruct a defective dam structure at Racine began in the first quarter of 2017 and reconstruction activities continued throughout 2018. An initial impairment recorded related to Racine is discussed in the “2017” section below. As of September 30, 2018, the Racine reconstruction project had accumulated new capital expenditures of $35 million . Due to a significant increase in estimated costs to complete the reconstruction project, in the third quarter of 2018, an impairment analysis was performed. 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 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 determination that the fair value of Racine in its condition as of September 30, 2018 was $0 . As a result, AEP recorded a pretax impairment of $35 million in Other Operation on the statements of income in the third quarter of 2018. In October 2018, AEP received authorization from the FERC to restart generation at Racine and generation resumed in November 2018. 2017 Merchant Generating Assets (Generation & Marketing Segment) In 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 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”). 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, 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 statements 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” section 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. 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 Desert Sky and Trent 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 statements of income.

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2018
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, with the exception of the rate of compensation increase, 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 2018 2017 2018 2017 Discount Rate 4.30 % 3.65 % 4.30 % 3.60 % Interest Crediting Rate 4.00 % 4.00 % NA NA NA Not applicable. Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2018 2017 AEP 4.85 % 4.80 % AEP Texas 4.95 % 4.90 % APCo 4.75 % 4.60 % I&M 4.90 % 4.85 % OPCo 5.00 % 4.95 % PSO 4.90 % 4.90 % SWEPCo 4.85 % 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. 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 2018 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. 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, Assumption 2018 2017 2016 2018 2017 2016 Discount Rate 3.65 % 4.05 % 4.30 % 3.60 % 4.10 % 4.30 % Interest Crediting Rate 4.00 % 4.00 % 4.00 % NA NA NA Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 6.00 % 6.75 % 7.00 % NA Not applicable. Pension Plans Year Ended December 31, Assumption – Rate of Compensation Increase (a) 2018 2017 2016 AEP 4.85 % 4.80 % 4.75 % AEP Texas 4.95 % 4.90 % 4.85 % APCo 4.75 % 4.60 % 4.55 % I&M 4.90 % 4.85 % 4.80 % OPCo 5.00 % 4.95 % 4.85 % PSO 4.90 % 4.90 % 4.90 % SWEPCo 4.85 % 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. 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 2018 2017 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2024 Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2018 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets For the year ended December 31, 2018, the pension and OPEB plans had an actuarial gain due to an increase in the discount rate as well as updated estimates for future medical expenses in the OPEB plans. For the year ended December 31, 2017, the pension plans had an actuarial loss due to a decrease in the discount rate. The OPEB plans had an actuarial gain primarily due to a change in medical benefits for retirees which was partially offset by a decrease in the discount rate. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,215.8 $ 5,085.8 $ 1,332.0 $ 1,447.4 Service Cost 97.6 96.5 11.6 11.2 Interest Cost 187.8 203.1 47.4 59.3 Actuarial (Gain) Loss (306.3 ) 182.4 (100.1 ) (97.5 ) Benefit Payments (384.6 ) (352.0 ) (133.6 ) (128.6 ) Participant Contributions — — 36.5 39.5 Medicare Subsidy — — 0.7 0.7 Benefit Obligation as of December 31, $ 4,810.3 $ 5,215.8 $ 1,194.5 $ 1,332.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 5,174.1 $ 4,827.3 $ 1,732.5 $ 1,545.9 Actual Gain (Loss) on Plan Assets (104.9 ) 600.0 (118.3 ) 271.6 Company Contributions (a) 11.3 98.8 17.1 4.1 Participant Contributions — — 36.5 39.5 Benefit Payments (384.6 ) (352.0 ) (133.6 ) (128.6 ) Fair Value of Plan Assets as of December 31, $ 4,695.9 $ 5,174.1 $ 1,534.2 $ 1,732.5 Funded (Underfunded) Status as of December 31, $ (114.4 ) $ (41.7 ) $ 339.7 $ 400.5 (a) Contributions to the qualified pension plan were $0 and $93 million for the years ended December 31, 2018 and 2017 , respectively. Contributions to the nonqualified pension plans were $11 million and $6 million for the years ended December 31, 2018 and 2017 , respectively. Pension Plans OPEB December 31, AEP 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ 36.3 $ 392.2 $ 463.0 Other Current Liabilities – Accrued Short-term Benefit Liability (5.7 ) (6.2 ) (2.8 ) (3.2 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (108.7 ) (71.8 ) (49.7 ) (59.3 ) Funded (Underfunded) Status $ (114.4 ) $ (41.7 ) $ 339.7 $ 400.5 AEP Texas Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 441.3 $ 421.7 $ 107.1 $ 120.4 Service Cost 9.2 8.6 0.9 0.9 Interest Cost 16.0 17.1 3.8 4.9 Actuarial (Gain) Loss (20.9 ) 25.6 (8.3 ) (11.9 ) Benefit Payments (36.3 ) (31.7 ) (10.7 ) (10.8 ) Participant Contributions — — 3.1 3.6 Benefit Obligation as of December 31, $ 409.3 $ 441.3 $ 95.9 $ 107.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 455.9 $ 416.6 $ 147.3 $ 134.1 Actual Gain (Loss) on Plan Assets (9.3 ) 61.8 (14.6 ) 20.4 Company Contributions 0.4 9.2 4.8 — Participant Contributions — — 3.1 3.6 Benefit Payments (36.3 ) (31.7 ) (10.7 ) (10.8 ) Fair Value of Plan Assets as of December 31, $ 410.7 $ 455.9 $ 129.9 $ 147.3 Funded Status as of December 31, $ 1.4 $ 14.6 $ 34.0 $ 40.2 Pension Plans OPEB December 31, AEP Texas 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 5.2 $ 18.6 $ 34.0 $ 40.2 Other Current Liabilities – Accrued Short-term Benefit Liability (0.4 ) (0.4 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (3.4 ) (3.6 ) — — Funded Status $ 1.4 $ 14.6 $ 34.0 $ 40.2 APCo Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 665.0 $ 654.0 $ 236.5 $ 255.6 Service Cost 9.3 9.4 1.1 1.1 Interest Cost 23.5 25.7 8.2 10.6 Actuarial (Gain) Loss (49.2 ) 15.7 (21.9 ) (13.4 ) Benefit Payments (45.5 ) (39.8 ) (24.7 ) (24.3 ) Participant Contributions — — 6.1 6.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 603.1 $ 665.0 $ 205.5 $ 236.5 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 651.7 $ 606.4 $ 273.4 $ 246.9 Actual Gain (Loss) on Plan Assets (12.9 ) 74.9 (18.7 ) 41.6 Company Contributions — 10.2 2.3 2.5 Participant Contributions — — 6.1 6.7 Benefit Payments (45.5 ) (39.8 ) (24.7 ) (24.3 ) Fair Value of Plan Assets as of December 31, $ 593.3 $ 651.7 $ 238.4 $ 273.4 Funded (Underfunded) Status as of December 31, $ (9.8 ) $ (13.3 ) $ 32.9 $ 36.9 Pension Plans OPEB December 31, APCo 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 62.3 $ 74.6 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.1 ) (2.5 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.8 ) (13.3 ) (27.3 ) (35.2 ) Funded (Underfunded) Status $ (9.8 ) $ (13.3 ) $ 32.9 $ 36.9 I&M Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 624.3 $ 611.6 $ 153.5 $ 167.6 Service Cost 13.6 14.0 1.6 1.6 Interest Cost 22.1 24.3 5.4 6.9 Actuarial (Gain) Loss (53.9 ) 10.8 (10.6 ) (12.0 ) Benefit Payments (39.1 ) (36.4 ) (16.2 ) (15.6 ) Participant Contributions — — 4.5 4.9 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 567.0 $ 624.3 $ 138.3 $ 153.5 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 636.7 $ 586.1 $ 211.1 $ 186.6 Actual Gain (Loss) on Plan Assets (13.8 ) 74.0 (12.1 ) 35.2 Company Contributions — 13.0 — — Participant Contributions — — 4.5 4.9 Benefit Payments (39.1 ) (36.4 ) (16.2 ) (15.6 ) Fair Value of Plan Assets as of December 31, $ 583.8 $ 636.7 $ 187.3 $ 211.1 Funded Status as of December 31, $ 16.8 $ 12.4 $ 49.0 $ 57.6 Pension Plans OPEB December 31, I&M 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 18.0 $ 13.4 $ 49.0 $ 57.6 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.2 ) (1.0 ) — — Funded Status $ 16.8 $ 12.4 $ 49.0 $ 57.6 OPCo Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 501.1 $ 492.9 $ 144.3 $ 164.0 Service Cost 7.7 7.5 0.9 0.9 Interest Cost 17.7 19.4 5.1 6.7 Actuarial (Gain) Loss (36.6 ) 13.1 (9.4 ) (16.6 ) Benefit Payments (36.0 ) (31.8 ) (15.8 ) (15.5 ) Participant Contributions — — 4.3 4.7 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 453.9 $ 501.1 $ 129.5 $ 144.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 509.1 $ 473.8 $ 198.5 $ 182.6 Actual Gain (Loss) on Plan Assets (7.0 ) 58.9 (11.6 ) 26.7 Company Contributions — 8.2 — — Participant Contributions — — 4.3 4.7 Benefit Payments (36.0 ) (31.8 ) (15.8 ) (15.5 ) Fair Value of Plan Assets as of December 31, $ 466.1 $ 509.1 $ 175.4 $ 198.5 Funded Status as of December 31, $ 12.2 $ 8.0 $ 45.9 $ 54.2 Pension Plans OPEB December 31, OPCo 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 12.6 $ 8.4 $ 45.9 $ 54.2 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (0.4 ) (0.4 ) — — Funded Status $ 12.2 $ 8.0 $ 45.9 $ 54.2 PSO Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 276.6 $ 266.7 $ 69.4 $ 77.6 Service Cost 7.0 6.4 0.7 0.7 Interest Cost 9.9 10.7 2.5 3.2 Actuarial (Gain) Loss (18.9 ) 10.1 (5.6 ) (7.5 ) Benefit Payments (20.8 ) (17.3 ) (6.7 ) (6.9 ) Participant Contributions — — 2.0 2.3 Benefit Obligation as of December 31, $ 253.8 $ 276.6 $ 62.3 $ 69.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 287.8 $ 266.0 $ 95.5 $ 86.4 Actual Gain (Loss) on Plan Assets (5.9 ) 33.6 (9.2 ) 13.7 Company Contributions 0.1 5.5 2.7 — Participant Contributions — — 2.0 2.3 Benefit Payments (20.8 ) (17.3 ) (6.7 ) (6.9 ) Fair Value of Plan Assets as of December 31, $ 261.2 $ 287.8 $ 84.3 $ 95.5 Funded Status as of December 31, $ 7.4 $ 11.2 $ 22.0 $ 26.1 Pension Plans OPEB December 31, PSO 2018 2017 2018 2017 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 9.7 $ 13.9 $ 22.0 $ 26.1 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (2.1 ) (2.5 ) — — Funded Status $ 7.4 $ 11.2 $ 22.0 $ 26.1 SWEPCo Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 314.6 $ 296.6 $ 80.3 $ 86.9 Service Cost 9.3 8.7 0.9 0.9 Interest Cost 11.3 12.3 2.8 3.6 Actuarial (Gain) Loss (19.2 ) 16.3 (5.9 ) (6.2 ) Benefit Payments (24.6 ) (19.3 ) (7.7 ) (7.4 ) Participant Contributions — — 2.3 2.5 Benefit Obligation as of December 31, $ 291.4 $ 314.6 $ 72.7 $ 80.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 311.7 $ 287.3 $ 110.4 $ 96.8 Actual Gain (Loss) on Plan Assets (7.3 ) 34.6 (9.2 ) 18.5 Company Contributions 1.2 9.1 2.7 — Participant Contributions — — 2.3 2.5 Benefit Payments (24.6 ) (19.3 ) (7.7 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 281.0 $ 311.7 $ 98.5 $ 110.4 Funded (Underfunded) Status as of December 31, $ (10.4 ) $ (2.9 ) $ 25.8 $ 30.1 Pension Plans OPEB December 31, SWEPCo 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.8 $ 30.1 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (10.2 ) (2.7 ) — — Funded (Underfunded) Status $ (10.4 ) $ (2.9 ) $ 25.8 $ 30.1 Amounts Included in Regulatory Assets, Deferred Income Taxes, AOCI and Income Tax Expense The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes, AOCI and Income Tax Expense and the items attributable to the change in these components: AEP Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 1,355.2 $ 1,354.2 $ 419.8 $ 309.9 Prior Service Credit — — (347.2 ) (416.3 ) Recorded as Regulatory Assets $ 1,267.9 $ 1,271.3 $ 52.5 $ (82.4 ) Deferred Income Taxes 18.4 17.4 4.2 (5.0 ) Net of Tax AOCI 68.9 53.9 15.9 (15.6 ) Income Tax Expense (a) — 11.6 — (3.4 ) AEP Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 88.8 $ (132.8 ) $ 120.4 $ (267.8 ) Amortization of Actuarial Loss (87.8 ) (82.8 ) (10.5 ) (36.7 ) Amortization of Prior Service Credit (Cost) — (1.0 ) 69.1 69.1 Change for the Year Ended December 31, $ 1.0 $ (216.6 ) $ 179.0 $ (235.4 ) AEP Texas Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 182.0 $ 175.2 $ 38.0 $ 23.9 Prior Service Credit — — (29.5 ) (35.4 ) Recorded as Regulatory Assets $ 168.2 $ 161.4 $ 8.7 $ (10.2 ) Deferred Income Taxes 2.9 2.9 — (0.3 ) Net of Tax AOCI 10.9 8.9 (0.2 ) (0.8 ) Income Tax Expense (a) — 2.0 — (0.2 ) AEP Texas Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 14.0 $ (11.1 ) $ 14.9 $ (23.6 ) Amortization of Actuarial Loss (7.2 ) (7.0 ) (0.8 ) (3.2 ) Amortization of Prior Service Credit — — 5.9 5.8 Change for the Year Ended December 31, $ 6.8 $ (18.1 ) $ 20.0 $ (21.0 ) APCo Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 172.2 $ 182.5 $ 58.9 $ 48.0 Prior Service Credit — — (50.4 ) (60.4 ) Recorded as Regulatory Assets $ 169.6 $ 179.9 $ 2.6 $ (11.1 ) Deferred Income Taxes 0.5 0.5 1.2 (0.3 ) Net of Tax AOCI 2.1 1.7 4.7 (0.8 ) Income Tax Expense (a) — 0.4 — (0.2 ) APCo Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 0.3 $ (23.3 ) $ 12.8 $ (38.6 ) Amortization of Actuarial Loss (10.6 ) (10.4 ) (1.9 ) (6.3 ) Amortization of Prior Service Credit (Cost) — (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (10.3 ) $ (33.9 ) $ 20.9 $ (34.8 ) I&M Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 80.6 $ 94.9 $ 54.7 $ 42.0 Prior Service Credit — — (47.4 ) (56.9 ) Recorded as Regulatory Assets $ 78.4 $ 91.8 $ 6.5 $ (14.0 ) Deferred Income Taxes 0.5 0.7 0.2 (0.2 ) Net of Tax AOCI 1.7 2.0 0.6 (0.6 ) Income Tax Expense (a) — 0.4 — (0.1 ) I&M Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ (4.5 ) $ (28.6 ) $ 13.9 $ (34.9 ) Amortization of Actuarial Loss (9.8 ) (9.7 ) (1.2 ) (4.4 ) Amortization of Prior Service Credit (Cost) — (0.2 ) 9.5 9.4 Change for the Year Ended December 31, $ (14.3 ) $ (38.5 ) $ 22.2 $ (29.9 ) OPCo Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 180.7 $ 189.6 $ 35.5 $ 22.6 Prior Service Credit — — (34.7 ) (41.6 ) Recorded as Regulatory Assets $ 180.7 $ 189.6 $ 0.8 $ (19.0 ) OPCo Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.9 ) $ (18.0 ) $ 14.0 $ (31.3 ) Amortization of Actuarial Loss (8.0 ) (7.8 ) (1.1 ) (4.3 ) Amortization of Prior Service Credit (Cost) — (0.1 ) 6.9 6.9 Change for the Year Ended December 31, $ (8.9 ) $ (25.9 ) $ 19.8 $ (28.7 ) PSO Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 77.6 $ 78.8 $ 28.3 $ 19.8 Prior Service Credit — — (21.6 ) (25.9 ) Recorded as Regulatory Assets $ 77.6 $ 78.8 $ 6.7 $ (6.1 ) PSO Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 3.2 $ (7.9 ) $ 9.0 $ (15.5 ) Amortization of Actuarial Loss (4.4 ) (4.3 ) (0.5 ) (2.0 ) Amortization of Prior Service Credit — — 4.3 4.3 Change for the Year Ended December 31, $ (1.2 ) $ (12.2 ) $ 12.8 $ (13.2 ) SWEPCo Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 97.4 $ 97.4 $ 33.9 $ 24.7 Prior Service Credit — — (26.2 ) (31.4 ) Recorded as Regulatory Assets $ 97.4 $ 97.4 $ 4.9 $ (3.7 ) Deferred Income Taxes — — 0.7 (0.6 ) Net of Tax AOCI — — 2.1 (2.0 ) Income Tax Expense (a) — — — (0.4 ) SWEPCo Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 5.5 $ (1.5 ) $ 9.8 $ (18.4 ) Amortization of Actuarial Loss (5.5 ) (4.9 ) (0.6 ) (2.3 ) Amortization of Prior Service Credit (Cost) — (0.1 ) 5.2 5.2 Change for the Year Ended December 31, $ — $ (6.5 ) $ 14.4 $ (15.5 ) (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. 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 2018 2017 2018 2017 AEP Texas 8.7 % 8.8 % 8.5 % 8.5 % APCo 12.6 % 12.6 % 15.5 % 15.8 % I&M 12.4 % 12.3 % 12.2 % 12.2 % OPCo 9.9 % 9.8 % 11.4 % 11.5 % PSO 5.6 % 5.6 % 5.5 % 5.5 % SWEPCo 6.0 % 6.0 % 6.4 % 6.4 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2018 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities (a): Domestic $ 277.3 $ — $ — $ — $ 277.3 5.9 % International 384.1 — — — 384.1 8.2 % Options — 18.3 — — 18.3 0.4 % Common Collective Trusts (c) — — — 370.1 370.1 7.9 % Subtotal – Equities 661.4 18.3 — 370.1 1,049.8 22.4 % Fixed Income (a): United States Government and Agency Securities 0.2 1,512.5 — — 1,512.7 32.2 % Corporate Debt — 1,082.9 — — 1,082.9 23.0 % Foreign Debt — 221.6 — — 221.6 4.7 % State and Local Government — 28.2 — — 28.2 0.6 % Other – Asset Backed — 7.4 — — 7.4 0.2 % Subtotal – Fixed Income 0.2 2,852.6 — — 2,852.8 60.7 % Infrastructure (c) — — — 72.2 72.2 1.5 % Real Estate (c) — — — 220.4 220.4 4.7 % Alternative Investments (c) — — — 444.6 444.6 9.5 % Cash and Cash Equivalents (c) (0.4 ) 36.3 — 11.9 47.8 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 8.3 8.3 0.2 % Total $ 661.2 $ 2,907.2 $ — $ 1,127.5 $ 4,695.9 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (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 presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2018 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 233.3 $ — $ — $ — $ 233.3 15.2 % International 185.9 — — — 185.9 12.1 % Options — 4.3 — — 4.3 0.3 % Common Collective Trusts (b) — — — 226.2 226.2 14.7 % Subtotal – Equities 419.2 4.3 — 226.2 649.7 42.3 % Fixed Income: Common Collective Trust – Debt (b) — — — 163.6 163.6 10.7 % United States Government and Agency Securities 0.2 181.5 — — 181.7 11.8 % Corporate Debt — 188.6 — — 188.6 12.3 % Foreign Debt — 35.0 — — 35.0 2.3 % State and Local Government 41.8 11.8 — — 53.6 3.5 % Other – Asset Backed — 0.2 — — 0.2 — % Subtotal – Fixed Income 42.0 417.1 — 163.6 622.7 40.6 % Trust Owned Life Insurance: International Equities — 49.4 — — 49.4 3.2 % United States Bonds — 154.4 — — 154.4 10.1 % Subtotal – Trust Owned Life Insurance — 203.8 — — 203.8 13.3 % Cash and Cash Equivalents (b) 54.4 — — 4.8 59.2 3.9 % Other – Pending Transactions and Accrued Income (a) — — — (1.2 ) (1.2 ) (0.1 )% Total $ 515.6 $ 625.2 $ — $ 393.4 $ 1,534.2 100.0 % (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, 2017 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities (a): Domestic $ 318.6 $ — $ — $ — $ 318.6 6.2 % International 507.7 — — — 507.7 9.8 % Options — 26.9 — — 26.9 0.5 % Common Collective Trusts (c) — — — 452.9 452.9 8.7 % Subtotal – Equities 826.3 26.9 — 452.9 1,306.1 25.2 % Fixed Income (a): United States Government and Agency Securities — 1,376.5 — — 1,376.5 26.6 % Corporate Debt — 1,277.0 — — 1,277.0 24.7 % Foreign Debt — 296.9 — — 296.9 5.7 % State and Local Government — 31.7 — — 31.7 0.6 % Other – Asset Backed — 10.2 — — 10.2 0.2 % Subtotal – Fixed Income — 2,992.3 — — 2,992.3 57.8 % Infrastructure (c) — — — 59.5 59.5 1.2 % Real Estate (c) — — — 290.3 290.3 5.6 % Alternative Investments (c) — — — 446.0 446.0 8.6 % Cash and Cash Equivalents (c) 0.4 35.6 — 21.2 57.2 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 22.7 22.7 0.5 % Total $ 826.7 $ 3,054.8 $ — $ 1,292.6 $ 5,174.1 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (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 (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. 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 $ 4,560.7 $ 393.2 $ 588.3 $ 536.3 $ 438.3 $ 238.0 $ 271.6 Nonqualified Pension Plans 64.9 3.6 0.2 0.6 0.2 2.2 1.2 Total as of December 31, 2018 $ 4,625.6 $ 396.8 $ 588.5 $ 536.9 $ 438.5 $ 240.2 $ 272.8 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 Obligations in Excess of Fair Values The tables below show the underfunded pension plans that had obligations in excess of plan assets. Projected Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,810.3 $ 3.8 $ 603.1 $ 1.2 $ 0.4 $ 2.3 $ 291.4 Fair Value of Plan Assets 4,695.9 — 593.3 — — — 281.0 Underfunded Projected Benefit Obligation as of December 31, 2018 $ (114.4 ) $ (3.8 ) $ (9.8 ) $ (1.2 ) $ (0.4 ) $ (2.3 ) $ (10.4 ) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 78.0 $ 4.0 $ 665.0 $ 1.0 $ 0.4 $ 2.7 $ 314.6 Fair Value of Plan Assets — — 651.7 — — — 311.7 Underfunded Projected Benefit Obligation as of December 31, 2017 $ (78.0 ) $ (4.0 ) $ (13.3 ) $ (1.0 ) $ (0.4 ) $ (2.7 ) $ (2.9 ) Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Accumulated Benefit Obligation $ 64.9 $ 3.6 $ 0.2 $ 0.6 $ 0.2 $ 2.2 $ 1.2 Fair Value of Plan Assets — — — — — — — Underfunded Accumulated Benefit Obligation as of December 31, 2018 $ (64.9 ) $ (3.6 ) $ (0.2 ) $ (0.6 ) $ (0.2 ) $ (2.2 ) $ (1.2 ) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 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 ) 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 2019 : Company Pension Plans OPEB (in millions) AEP $ 98.7 $ 4.5 AEP Texas 8.0 0.1 APCo 7.7 2.1 I&M 1.1 — OPCo 0.5 — PSO 0.2 — SWEPCo 7.9 — 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 interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 339.8 $ 30.8 $ 43.4 $ 36.2 $ 34.3 $ 19.0 $ 21

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2018
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 at auction 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 are 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, interest expense, income tax expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2018 , 2017 and 2016 and reportable segment balance sheet information as of December 31, 2018 and 2017 . Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2018 Revenues from: External Customers $ 9,556.7 $ 4,552.3 $ 248.6 $ 1,818.1 $ 20.0 $ — $ 16,195.7 Other Operating Segments 88.8 100.8 555.5 122.2 75.1 (942.4 ) — Total Revenues $ 9,645.5 $ 4,653.1 $ 804.1 $ 1,940.3 $ 95.1 $ (942.4 ) $ 16,195.7 Asset Impairments and Other Related Charges $ 3.4 $ — $ — $ 47.7 $ 19.5 $ — $ 70.6 Depreciation and Amortization 1,316.2 734.1 137.8 41.0 0.4 57.1 (b) 2,286.6 Interest and Investment Income 11.7 4.2 2.5 13.1 31.0 (50.9 ) 11.6 Carrying Costs Income (Expense) 5.3 1.7 (0.4 ) — — — 6.6 Interest Expense 567.8 248.1 90.7 14.9 122.6 (59.7 ) (b) 984.4 Income Tax Expense (Benefit) 5.7 42.4 95.3 (49.2 ) 21.1 — 115.3 Net Income (Loss) $ 995.5 $ 527.4 $ 373.0 $ 134.7 $ (99.3 ) $ — $ 1,931.3 Gross Property Additions $ 2,282.2 $ 2,162.4 $ 1,614.1 $ 289.7 $ 16.3 $ (39.2 ) $ 6,325.5 Total Property, Plant and Equipment $ 45,365.1 $ 18,126.7 $ 8,659.5 $ 893.3 $ 395.2 $ (354.6 ) (b) $ 73,085.2 Accumulated Depreciation and Amortization 13,822.5 3,833.7 282.8 47.0 186.6 (186.5 ) (b) 17,986.1 Total Property, Plant and Equipment – Net $ 31,542.6 $ 14,293.0 $ 8,376.7 $ 846.3 $ 208.6 $ (168.1 ) (b) $ 55,099.1 Total Assets $ 38,874.3 $ 17,083.4 $ 9,543.7 $ 1,979.7 $ 4,036.5 (c) $ (2,714.8 ) (b) (d) $ 68,802.8 Investments in Equity Method Investees $ 39.6 $ 2.9 $ 750.9 $ 26.7 $ 26.1 $ — $ 846.2 Long-term Debt Due Within One Year: Nonaffiliated $ 1,066.3 $ 549.1 $ 85.0 $ 0.1 $ (2.0 ) (e) $ — $ 1,698.5 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 11,442.7 5,048.8 2,888.6 (0.3 ) 2,268.4 (e) — 21,648.2 Total Long-term Debt $ 12,559.0 $ 5,597.9 $ 2,973.6 $ 32.0 $ 2,266.4 $ (82.2 ) $ 23,346.7 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 (Expense) 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 425.6 127.2 189.8 189.7 37.4 — 969.7 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: Nonaffiliated $ 1,038.1 $ 663.1 $ 50.0 $ — $ 2.5 $ — $ 1,753.7 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 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 (Expense) 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 (Benefit) 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 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 (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 other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (d) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. (e) Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information. 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 integrated 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. 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 RTOs 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 the 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, 2018 , 2017 and 2016 and reportable segment balance sheet information as of December 31, 2018 and 2017 . State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2018 (in millions) Revenues from: External Customers $ 177.0 $ — $ — $ 177.0 Sales to AEP Affiliates 598.9 — — 598.9 Other Revenues 0.2 — — 0.2 Total Revenues $ 776.1 $ — $ — $ 776.1 Depreciation and Amortization $ 133.9 $ — $ — $ 133.9 Interest Income 1.3 104.6 (103.4 ) (a) 2.5 Allowance for Equity Funds Used During Construction 70.6 — — 70.6 Interest Expense 83.2 103.4 (103.4 ) (a) 83.2 Income Tax Expense 83.9 0.2 — 84.1 Net Income $ 314.9 $ 1.0 (b) $ — $ 315.9 Gross Property Additions $ 1,570.8 $ — $ — $ 1,570.8 Total Transmission Property $ 8,268.1 $ — $ — $ 8,268.1 Accumulated Depreciation and Amortization 271.9 — — 271.9 Total Transmission Property - Net $ 7,996.2 $ — $ — $ 7,996.2 Notes Receivable - Affiliated $ — $ 2,823.0 $ (2,823.0 ) (c) $ — Total Assets $ 8,406.8 $ 2,857.1 (d) $ (2,869.8 ) (e) $ 8,394.1 Total Long-Term Debt $ 2,850.0 $ 2,823.0 $ (2,850.0 ) (c) $ 2,823.0 State Transcos (f) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (f) 2017 (in millions) Revenues from: External Customers $ 138.0 $ — $ — $ 138.0 Sales to AEP Affiliates 568.1 — — 568.1 Other Revenues 0.8 — — 0.8 Total Revenues $ 706.9 $ — $ — $ 706.9 Depreciation and Amortization $ 95.7 $ — $ — $ 95.7 Interest Income 0.7 82.9 (82.4 ) (a) 1.2 Allowance for Equity Funds Used During Construction 49.0 — — 49.0 Interest Expense 70.2 82.4 (82.4 ) (a) 70.2 Income Tax Expense 142.0 0.2 — 142.2 Net Income $ 270.4 $ 0.3 (b) $ — $ 270.7 Gross Property Additions $ 1,522.5 $ — $ — $ 1,522.5 Total Transmission Property $ 6,770.5 $ — $ — $ 6,770.5 Accumulated Depreciation and Amortization 152.6 — — 152.6 Total Transmission Property - Net $ 6,617.9 $ — $ — $ 6,617.9 Notes Receivable - Affiliated $ — $ 2,550.4 $ (2,550.4 ) (c) $ — Total Assets $ 7,086.9 $ 2,590.1 (d) $ (2,594.9 ) (e) $ 7,082.1 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 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 (Benefit) 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 Assets $ 5,337.5 $ 1,987.7 (d) $ (1,975.4 ) (e) $ 5,349.8 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Includes elimination of AEPTCo Parent’s investments in the State Transcos. (e) Primarily relates to elimination of Notes Receivable from the State Transcos. (f) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Derivatives and Hedging

Derivatives and Hedging	12 Months Ended
	Dec. 31, 2018
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. The Registrants adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. See Note 2 - New Accounting Pronouncements for additional information. 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, 2018 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 371.1 — 66.4 40.9 7.8 15.2 4.5 Natural Gas MMBtus 87.9 — 4.0 2.3 — — 15.2 Heating Oil and Gasoline Gallons 7.4 1.5 1.4 0.7 1.8 0.7 0.8 Interest Rate USD $ 37.7 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 500.0 $ — $ — $ — $ — $ — $ — 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 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 $18 million and $9.4 million as of December 31, 2018 and 2017 , respectively. AEP netted cash collateral paid to third parties against short-term and long-term risk management liabilities in the amounts of $4 million and $9 million as of December 31, 2018 and 2017 , respectively. 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 as of December 31, 2018 and 2017 . 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, 2018 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 $ 397.5 $ 28.5 $ — $ 426.0 $ (263.2 ) $ 162.8 Long-term Risk Management Assets 276.4 16.0 — 292.4 (38.4 ) 254.0 Total Assets 673.9 44.5 — 718.4 (301.6 ) 416.8 Current Risk Management Liabilities 293.8 13.2 2.0 309.0 (254.0 ) 55.0 Long-term Risk Management Liabilities 225.7 56.1 15.4 297.2 (33.8 ) 263.4 Total Liabilities 519.5 69.3 17.4 606.2 (287.8 ) 318.4 Total MTM Derivative Contract Net Assets (Liabilities) $ 154.4 $ (24.8 ) $ (17.4 ) $ 112.2 $ (13.8 ) $ 98.4 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 AEP Texas Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 0.7 (0.5 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.7 (0.5 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.7 ) $ 0.5 $ (0.2 ) 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 APCo Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 114.4 $ (57.2 ) $ 57.2 Long-term Risk Management Assets 3.1 (2.2 ) 0.9 Total Assets 117.5 (59.4 ) 58.1 Current Risk Management Liabilities 56.7 (56.3 ) 0.4 Long-term Risk Management Liabilities 2.4 (2.2 ) 0.2 Total Liabilities 59.1 (58.5 ) 0.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 58.4 $ (0.9 ) $ 57.5 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 I&M Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (41.8 ) $ 8.6 Long-term Risk Management Assets 2.0 (1.4 ) 0.6 Total Assets 52.4 (43.2 ) 9.2 Current Risk Management Liabilities 41.1 (40.8 ) 0.3 Long-term Risk Management Liabilities 1.6 (1.5 ) 0.1 Total Liabilities 42.7 (42.3 ) 0.4 Total MTM Derivative Contract Net Assets (Liabilities) $ 9.7 $ (0.9 ) $ 8.8 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 OPCo Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 6.4 (0.6 ) 5.8 Long-term Risk Management Liabilities 93.8 — 93.8 Total Liabilities 100.2 (0.6 ) 99.6 Total MTM Derivative Contract Net Assets (Liabilities) $ (100.2 ) $ 0.6 $ (99.6 ) 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 ) PSO Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 10.9 $ (0.5 ) $ 10.4 Long-term Risk Management Assets — — — Total Assets 10.9 (0.5 ) 10.4 Current Risk Management Liabilities 1.7 (0.7 ) 1.0 Long-term Risk Management Liabilities — — — Total Liabilities 1.7 (0.7 ) 1.0 Total MTM Derivative Contract Net Assets $ 9.2 $ 0.2 $ 9.4 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 SWEPCo Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 5.6 $ (0.8 ) $ 4.8 Long-term Risk Management Assets — — — Total Assets 5.6 (0.8 ) 4.8 Current Risk Management Liabilities 1.5 (1.1 ) 0.4 Long-term Risk Management Liabilities 2.2 — 2.2 Total Liabilities 3.7 (1.1 ) 2.6 Total MTM Derivative Contract Net Assets $ 1.9 $ 0.3 $ 2.2 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 (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) All derivative contracts subject to a master netting arrangement or similar agreement are 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, 2018 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (10.4 ) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.9 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (1.9 ) (8.2 ) — — 0.1 Purchased Electricity for Resale 8.6 — 7.6 0.8 — — — Other Operation 1.7 0.4 0.2 0.2 0.3 0.2 0.2 Maintenance 1.9 0.4 0.4 0.2 0.4 0.2 0.2 Regulatory Assets (a) 27.9 (0.7 ) (0.7 ) 7.1 24.9 (1.1 ) (1.2 ) Regulatory Liabilities (a) 222.7 (0.5 ) 135.5 11.6 — 37.3 11.9 Total Gain (Loss) on Risk Management Contracts $ 291.3 $ (0.4 ) $ 141.1 $ 11.7 $ 25.6 $ 36.6 $ 11.2 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 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships: Carrying Amount of the Hedged Assets/(Liabilities) Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 (in millions) Long-Term Debt (a) $ (478.3 ) $ (489.3 ) $ 17.4 $ 6.1 (a) Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively. The pretax effects of fair value hedge accounting on income were as follows: Twelve Months Ended December 31, 2018 2017 2016 (in millions) Gain (Loss) on Interest Rate Contracts: Gain (Loss) on Fair Value Hedging Instruments (a) $ (11.3 ) $ (4.8 ) $ 1.6 Gain (Loss) on Fair Value Portion of Long-term Debt (a) 11.3 4.8 (1.6 ) (a) Gain (Loss) is included in Interest Expense on the statements of income. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report 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. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2018 , 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the years ended 2018 , 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the years ended 2018 , 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the years ended 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During the year ended 2018 , SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the years ended 2018 , 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income. Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2018 December 31, 2017 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Gain (Loss) Net of Tax $ (23.0 ) $ (12.6 ) $ (28.4 ) $ (13.0 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 10.4 (1.1 ) 5.5 (0.8 ) As of December 31, 2018 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 180 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2018 December 31, 2017 Interest Rate Expected to be Expected to be Reclassed to Reclassed to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) AEP Texas $ (4.4 ) $ (1.1 ) $ (4.5 ) $ (0.9 ) APCo 1.8 0.9 2.2 0.7 I&M (11.5 ) (1.6 ) (10.7 ) (1.3 ) OPCo 1.0 1.0 1.9 1.1 PSO 2.1 1.0 2.6 0.8 SWEPCo (3.3 ) (1.5 ) (6.0 ) (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 credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. 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. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2018 and 2017 . Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: December 31, 2018 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 225.5 $ 1.8 $ 181.0 APCo 0.9 — — I&M 0.5 — — SWEPCo 2.3 — 2.3 December 31, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 243.6 $ 1.3 $ 223.1 APCo 0.6 — 0.5 I&M 0.4 — 0.4 SWEPCo 0.2 — 0.1

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 23,346.7 $ 24,093.9 $ 21,173.3 $ 23,649.6 AEP Texas 3,881.3 3,964.6 3,649.3 3,964.8 AEPTCo 2,823.0 2,782.4 2,550.4 2,782.9 APCo 4,062.6 4,473.3 3,980.1 4,782.6 I&M 3,035.4 3,070.2 2,745.1 3,014.7 OPCo 1,716.6 1,919.7 1,719.3 2,064.3 PSO 1,287.0 1,361.9 1,286.5 1,457.1 SWEPCo 2,713.4 2,670.2 2,441.9 2,645.9 Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include 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 for additional information. The following is a summary of Other Temporary Investments: December 31, 2018 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 230.6 $ — $ — $ 230.6 Fixed Income Securities – Mutual Funds (b) 106.6 — (2.3 ) 104.3 Equity Securities – Mutual Funds 17.8 16.4 — 34.2 Total Other Temporary Investments $ 355.0 $ 16.4 $ (2.3 ) $ 369.1 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 (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, 2018 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 3.1 14.2 2.3 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, 2018 , 2017 and 2016 , see Note 3 - Comprehensive Income. Fair Value Measurements of Trust Assets for Decommissioning and Spent Nuclear Fuel 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, 2018 2017 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 22.5 $ — $ — $ 17.2 $ — $ — Fixed Income Securities: United States Government 996.1 26.7 (7.1 ) 981.2 29.7 (3.6 ) Corporate Debt 52.4 1.1 (1.9 ) 58.7 3.8 (1.2 ) State and Local Government 8.6 0.6 (0.2 ) 8.8 0.8 (0.2 ) Subtotal Fixed Income Securities 1,057.1 28.4 (9.2 ) 1,048.7 34.3 (5.0 ) Equity Securities – Domestic (a) 1,395.3 766.3 — 1,461.7 868.2 (75.5 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,474.9 $ 794.7 $ (9.2 ) $ 2,527.6 $ 902.5 $ (80.5 ) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $784 million and unrealized losses of $18 million . AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values. The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2018 2017 2016 (in millions) Proceeds from Investment Sales $ 2,010.0 $ 2,256.3 $ 2,957.7 Purchases of Investments 2,064.7 2,300.5 3,000.0 Gross Realized Gains on Investment Sales 47.5 200.7 46.1 Gross Realized Losses on Investment Sales 32.8 146.0 24.4 The base cost of fixed income securities was $1 billion and $1 billion as of December 31, 2018 and 2017 , respectively. The base cost of equity securities was $629 million and $594 million as of December 31, 2018 and 2017 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2018 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 359.4 After 1 year through 5 years 358.9 After 5 years through 10 years 176.1 After 10 years 162.7 Total $ 1,057.1 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, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 221.5 $ — $ — $ 9.1 $ 230.6 Fixed Income Securities – Mutual Funds 104.3 — — — 104.3 Equity Securities – Mutual Funds (b) 34.2 — — — 34.2 Total Other Temporary Investments 360.0 — — 9.1 369.1 Risk Management Assets Risk Management Commodity Contracts (c) (d) 3.8 326.5 340.9 (288.5 ) 382.7 Cash Flow Hedges: Commodity Hedges (c) — 24.1 12.7 (2.7 ) 34.1 Total Risk Management Assets 3.8 350.6 353.6 (291.2 ) 416.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 12.3 — — 10.2 22.5 Fixed Income Securities: United States Government — 996.1 — — 996.1 Corporate Debt — 52.4 — — 52.4 State and Local Government — 8.6 — — 8.6 Subtotal Fixed Income Securities — 1,057.1 — — 1,057.1 Equity Securities – Domestic (b) 1,395.3 — — — 1,395.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,407.6 1,057.1 — 10.2 2,474.9 Total Assets $ 1,771.4 $ 1,407.7 $ 353.6 $ (271.9 ) $ 3,260.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.2 $ 327.0 $ 185.6 $ (274.7 ) $ 242.1 Cash Flow Hedges: Commodity Hedges (c) — 24.8 36.8 (2.7 ) 58.9 Fair Value Hedges — 17.4 — — 17.4 Total Risk Management Liabilities $ 4.2 $ 369.2 $ 222.4 $ (277.4 ) $ 318.4 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) (f) 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) (f) $ 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 Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 156.7 $ — $ — $ — $ 156.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 0.7 $ — $ (0.5 ) $ 0.2 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 25.6 $ — $ — $ — $ 25.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) 0.1 59.1 58.3 (59.4 ) 58.1 Total Assets $ 25.7 $ 59.1 $ 58.3 $ (59.4 ) $ 83.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.2 $ 58.4 $ 0.5 $ (58.5 ) $ 0.6 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 42.1 $ 10.3 $ (43.2 ) $ 9.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 12.3 — — 10.2 22.5 Fixed Income Securities: United States Government — 996.1 — — 996.1 Corporate Debt — 52.4 — — 52.4 State and Local Government — 8.6 — — 8.6 Subtotal Fixed Income Securities — 1,057.1 — — 1,057.1 Equity Securities – Domestic (b) 1,395.3 — — — 1,395.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,407.6 1,057.1 — 10.2 2,474.9 Total Assets $ 1,407.6 $ 1,099.2 $ 10.3 $ (33.0 ) $ 2,484.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.1 $ 41.2 $ 1.4 $ (42.3 ) $ 0.4 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 27.6 $ — $ — $ — $ 27.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 99.4 $ (0.6 ) $ 99.6 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 10.8 $ (0.4 ) $ 10.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 1.3 $ (0.6 ) $ 1.0 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 ) $ — SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 5.6 $ (0.8 ) $ 4.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 3.3 $ (1.1 ) $ 2.6 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 (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, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(4) million in 2019, $1 million in periods 2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $108 million in 2019, $37 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032. 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, 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 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the years ended December 31, 2018 , 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2018 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2017 $ 40.3 $ 24.7 $ 7.6 $ (132.4 ) $ 6.2 $ 5.9 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 148.9 104.1 14.2 1.8 18.1 (4.8 ) Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 9.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 15.7 — — — — — Settlements (214.0 ) (127.9 ) (21.3 ) 4.6 (24.3 ) (2.1 ) Transfers into Level 3 (d) (e) 15.8 — — — — — Transfers out of Level 3 (e) (1.6 ) — (0.3 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 116.3 56.9 8.7 26.6 9.5 3.3 Balance as of December 31, 2018 $ 131.2 $ 57.8 $ 8.9 $ (99.4 ) $ 9.5 $ 2.3 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 (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, 2018 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 257.1 $ 212.5 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 176.57 $ 33.07 Natural Gas Contracts — 2.5 Discounted Cash Flow Forward Market Price (b) 2.18 3.54 2.47 FTRs 96.5 7.4 Discounted Cash Flow Forward Market Price (a) (11.68 ) 17.79 1.09 Total $ 353.6 $ 222.4 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 Natural Gas Contracts — 0.2 Discounted Cash Flow Forward Market Price (b) 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, 2018 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.4 $ 0.5 Discounted Cash Flow Forward Market Price $ 16.82 $ 62.65 $ 37.00 FTRs 55.9 — Discounted Cash Flow Forward Market Price 0.10 15.16 3.27 Total $ 58.3 $ 0.5 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, 2018 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.4 $ 0.9 Discounted Cash Flow Forward Market Price $ 16.82 $ 62.65 $ 37.00 FTRs 8.9 0.5 Discounted Cash Flow Forward Market Price (2.11 ) 6.21 1.06 Total $ 10.3 $ 1.4 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, 2018 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ — $ 99.4 Discounted Cash Flow Forward Market Price $ 26.29 $ 62.74 $ 42.50 Significant Unobservable Inputs December 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ — $ 132.4 Discounted Cash Flow Forward Market Price $ 30.52 $ 170.43 $ 44.62 Significant Unobservable Inputs December 31, 2018 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 10.8 $ 1.3 Discounted Cash Flow Forward Market Price $ (11.68 ) $ 10.30 $ (1.40 ) 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, 2018 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 2.5 Discounted Cash Flow Forward Market Price (b) $ 2.18 $ 3.54 $ 2.47 FTRs 5.6 0.8 Discounted Cash Flow Forward Market Price (a) (11.68 ) 10.30 (1.40 ) Total $ 5.6 $ 3.3 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 (b) $ 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 (a) Represents market prices in dollars per MWh. (b) 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, 2018 and 2017 : 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)

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Federal Tax Reform and Legislation In December 2017, Tax Reform legislation was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, including lowering the corporate federal income tax rate from 35% to 21%. As a result of this rate change, the Registrants’ deferred tax assets and liabilities were remeasured using the newly enacted rate of 21% in December 2017. In response to Tax Reform, the SEC staff issued Staff Accounting Bulletin 118 (SAB 118) in December 2017. SAB 118 provided for up to a one year period (the measurement period) in which to complete the required analyses and accounting required by Tax Reform. During 2017, AEP recorded provisional amounts for the income tax effects of Tax Reform. Throughout 2018, AEP continued to assess the impacts of legislative changes in the tax code as well as interpretative changes of the tax code. The measurement period adjustments recorded during 2018 were immaterial. The measurement period under SAB 118 ended in December 2018. However, Tax Reform uncertainties still remain and AEP will continue to monitor income tax effects that may change as a result of future legislation and further interpretation of Tax Reform based on proposed U.S. Treasury regulations and guidance from the IRS and state tax authorities. Federal Legislation The IRS has proposed new regulations that provide guidance regarding the additional first-year depreciation deduction under Section 168(k). The proposed regulations reflect changes as a result of Tax Reform and affect taxpayers with qualified depreciable property acquired and placed in service after September 27, 2017. Generally, AEP’s regulated utilities will not be eligible for any bonus depreciation for property acquired and placed in service after January 1, 2018 and AEP’s competitive businesses will be eligible for 100% expensing. However, for self-constructed property and other property placed in service in 2018 for which construction began prior to January 1, 2018, taxpayers are required to evaluate the contractual terms to determine if these additions qualify for 100% expensing under Tax Reform or 50% bonus depreciation as provided under prior tax law. During the fourth quarter of 2018, the IRS proposed new regulations that reflect changes as a result of Tax Reform concerning potential limitations on the deduction of business interest expense. These regulations require an allocation of net interest expense between regulated and competitive businesses within the consolidated tax return. This allocation is based upon net tax basis, and the proposed regulations provide a de minimis test under which all interest is deductible if less than 10% is allocable to the competitive businesses. Management continues to review and evaluate the proposed regulations and at this time expect to be able to deduct materially all business interest expense under this de minimis provision. Section 162(m) of the Internal Revenue Code generally limits the amount of compensation a company can deduct annually to $1 million for certain executive officers. The exemption from Section 162(m)’s deduction limit for performance-based compensation was repealed by Tax Reform, effective for taxable years ending after December 31, 2017. Management continues to evaluate whether any of its compensation plans qualify for transitional relief, such that payments made pursuant to these plans might be deductible. Status of Tax Reform Regulatory Proceedings For AEP’s various regulatory jurisdictions where the regulatory effects of Tax Reform proceedings have not been fully resolved, the table below summarizes the current status. See Note 4 - Rate Matters for additional information. Registrant (Jurisdiction) Change in Tax Rate Excess ADIT Subject to Normalization Requirements Excess ADIT Not Subject to Normalization Requirements AEP Texas (Texas-Distribution) Order Issued Order Issued Order Issued – Partial (a) AEP Texas (Texas-Transmission) Order Issued To be addressed in a later filing To be addressed in a later filing APCo (Virginia) Legislation Enacted – Case Pending (b) Legislation Enacted – Case Pending (b) Order Issued – Partial; Separate Case Pending (c) I&M (Michigan) Order Issued Case Pending Case Pending SWEPCo (Louisiana) Case Pending – Rates Implemented (d) Case Pending – Rates Implemented (d) Case Pending – Rates Implemented (d) SWEPCo (Texas) Order Issued To be addressed in a later filing To be addressed in a later filing PJM FERC Transmission Settlement Approved (e) Settlement Approved (e) Settlement Approved (e) SPP FERC Transmission To be addressed in a later filing To be addressed in a later filing To be addressed in a later filing (a) A portion of the Excess ADIT that is not subject to rate normalization requirements is to be addressed in a later filing. (b) Legislation has been issued for a blanket amount that is subject to true-up and final commission approval. (c) In October 2018, the Virginia SCC issued an order approving APCo’s request to refund a portion of the Excess ADIT that is not subject to rate normalization requirements to customers. The remainder is to be addressed in a separate pending case. (d) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval. (e) An ALJ has approved a settlement. The settlement is subject to final FERC ruling. Income Tax Expense (Benefit) The details of the Registrants’ Income Tax Expense (Benefit) before discontinued operations as reported are as follows: Year Ended December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (31.7 ) $ 37.0 $ (14.2 ) $ (31.9 ) $ 60.9 $ 55.6 $ 35.6 $ 18.3 Deferred 112.8 (16.4 ) 82.3 (24.6 ) (44.1 ) (36.9 ) (34.7 ) (0.5 ) Deferred Investment Tax Credits 9.2 (1.5 ) — 0.1 (4.7 ) — (2.0 ) (1.4 ) Total Federal 90.3 19.1 68.1 (56.4 ) 12.1 18.7 (1.1 ) 16.4 State and Local: Current 30.8 1.8 (0.6 ) 3.7 15.8 4.6 (0.2 ) 2.3 Deferred (8.5 ) (0.1 ) 16.6 7.8 1.2 0.7 3.6 1.7 Deferred Investment Tax Credits 2.7 — — — — — 2.7 — Total State and Local 25.0 1.7 16.0 11.5 17.0 5.3 6.1 4.0 Income Tax Expense (Benefit) Before Discontinued Operations $ 115.3 $ 20.8 $ 84.1 $ (44.9 ) $ 29.1 $ 24.0 $ 5.0 $ 20.4 Year Ended December 31, 2017 AEP AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (4.0 ) $ (85.7 ) $ (130.4 ) $ 15.3 $ (106.5 ) $ 11.2 $ (77.1 ) $ (30.1 ) Deferred 856.6 63.3 254.8 166.9 202.1 141.3 122.7 84.8 Deferred Investment Tax Credits 48.6 (1.6 ) — (0.1 ) (4.7 ) — (1.6 ) (1.4 ) Total Federal 901.2 (24.0 ) 124.4 182.1 90.9 152.5 44.0 53.3 State and Local: Current 16.0 0.6 1.1 (1.4 ) (8.1 ) 0.2 (0.2 ) (0.9 ) Deferred 44.9 — 16.7 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 17.8 3.2 (9.5 ) 6.8 6.1 (5.2 ) Income Tax Expense (Benefit) Before Discontinued Operations $ 969.7 $ (23.4 ) $ 142.2 $ 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 (Benefit) Before Discontinued Operations $ (73.7 ) $ 59.9 $ 94.1 $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. The following are reconciliations for the Registrants between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported: AEP Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 1,931.3 $ 1,928.9 $ 618.0 Less: Equity Earnings – Dolet Hills (2.7 ) — — Discontinued Operations (Net of Income Tax of $0, $0 and $0 in 2018, 2017 and 2016, Respectively) — — 2.5 Income Tax Expense (Benefit) Before Discontinued Operations 115.3 969.7 (73.7 ) Pretax Income $ 2,043.9 $ 2,898.6 $ 546.8 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 429.2 $ 1,014.5 $ 191.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 24.4 60.2 41.7 Investment Tax Credit Amortization (20.2 ) (18.8 ) (12.3 ) State and Local Income Taxes, Net 19.7 54.7 (20.7 ) Removal Costs (19.8 ) (32.7 ) (39.8 ) AFUDC (29.4 ) (37.4 ) (44.8 ) Valuation Allowance — (1.8 ) (128.3 ) U.K. Windfall Tax — — (12.9 ) Tax Reform Adjustments (10.9 ) (26.7 ) — Tax Adjustments — (35.8 ) (43.9 ) Tax Reform Excess ADIT Reversal (257.2 ) — — Other (20.5 ) (6.5 ) (4.1 ) Income Tax Expense (Benefit) Before Discontinued Operations $ 115.3 $ 969.7 $ (73.7 ) Effective Income Tax Rate 5.6 % 33.5 % (13.5 ) % AEP Texas Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 211.3 $ 310.5 $ 146.6 Discontinued Operations (Net of Income Tax of $0, $0 and $27.6 in 2018, 2017 and 2016, Respectively) — — 48.8 Income Tax Expense (Benefit) 20.8 (23.4 ) 59.9 Pretax Income $ 232.1 $ 287.1 $ 255.3 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 48.7 $ 100.5 $ 89.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: State and Local Income Taxes, Net 1.3 0.4 (6.0 ) AFUDC (4.2 ) (3.9 ) (3.2 ) Parent Company Loss Benefit (3.1 ) — (2.5 ) Tax Reform Adjustments (11.0 ) (117.4 ) — Tax Adjustments — (4.2 ) (4.9 ) U.K. Windfall Tax — — (12.9 ) Tax Reform Excess ADIT Reversal (11.8 ) — — Other 0.9 1.2 — Income Tax Expense (Benefit) Before Discontinued Operations $ 20.8 $ (23.4 ) $ 59.9 Effective Income Tax Rate 9.0 % (8.2 ) % 23.5 % AEPTCo Years Ended December 31, 2018 2017 (a) 2016 (in millions) Net Income $ 315.9 $ 270.7 $ 192.7 Income Tax Expense 84.1 142.2 94.1 Pretax Income $ 400.0 $ 412.9 $ 286.8 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 84.0 $ 144.5 $ 100.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: AFUDC (14.1 ) (17.0 ) (18.3 ) State and Local Income Taxes, Net 12.6 13.1 11.4 Tax Reform Adjustments — 0.6 — Other 1.6 1.0 0.6 Income Tax Expense $ 84.1 $ 142.2 $ 94.1 Effective Income Tax Rate 21.0 % 34.4 % 32.8 % (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. APCo Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 367.8 $ 331.3 $ 369.1 Income Tax Expense (Benefit) (44.9 ) 185.3 199.1 Pretax Income $ 322.9 $ 516.6 $ 568.2 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 67.8 $ 180.8 $ 198.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.5 18.0 19.3 State and Local Income Taxes, Net 9.1 3.5 6.0 Removal Costs (9.6 ) (12.4 ) (12.0 ) AFUDC (4.3 ) (5.0 ) (6.1 ) Tax Reform Adjustments 0.1 4.3 — Tax Reform Excess ADIT Reversal (108.5 ) — — Other (8.0 ) (3.9 ) (7.0 ) Income Tax Expense (Benefit) $ (44.9 ) $ 185.3 $ 199.1 Effective Income Tax Rate (13.9 ) % 35.9 % 35.0 % I&M Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 261.3 $ 186.7 $ 239.9 Income Tax Expense 29.1 81.4 67.5 Pretax Income $ 290.4 $ 268.1 $ 307.4 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 61.0 $ 93.8 $ 107.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation (0.7 ) 11.4 6.7 Investment Tax Credit Amortization (4.7 ) (4.7 ) (4.7 ) State and Local Income Taxes, Net 13.4 (1.0 ) 2.4 Removal Costs (8.0 ) (13.3 ) (21.3 ) AFUDC (2.5 ) (5.6 ) (7.3 ) Tax Adjustments — 2.7 (14.2 ) Tax Reform Adjustments — (2.9 ) — Tax Reform Excess ADIT Reversal (25.8 ) — — Other (3.6 ) 1.0 (1.7 ) Income Tax Expense $ 29.1 $ 81.4 $ 67.5 Effective Income Tax Rate 10.0 % 30.4 % 22.0 % OPCo Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 325.5 $ 323.9 $ 282.2 Income Tax Expense 24.0 159.3 143.8 Pretax Income $ 349.5 $ 483.2 $ 426.0 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 73.4 $ 169.1 $ 149.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 2.6 7.6 7.1 State and Local Income Taxes, Net 4.2 4.4 3.8 Tax Reform Adjustments — (14.4 ) — Tax Reform Excess ADIT Reversal (51.0 ) — — Parent Company Loss Benefit (5.5 ) (0.2 ) (7.2 ) Other 0.3 (7.2 ) (9.0 ) Income Tax Expense $ 24.0 $ 159.3 $ 143.8 Effective Income Tax Rate 6.9 % 33.0 % 33.8 % PSO Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 83.2 $ 72.0 $ 100.0 Income Tax Expense 5.0 50.1 54.4 Pretax Income $ 88.2 $ 122.1 $ 154.4 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 18.5 $ 42.7 $ 54.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 1.0 0.3 0.8 Investment Tax Credit Amortization (1.7 ) (1.6 ) (1.4 ) Parent Company Loss Benefit (1.4 ) — — State and Local Income Taxes, Net 4.8 4.0 4.2 Tax Reform Adjustments — 2.8 — Tax Reform Excess ADIT Reversal (15.5 ) — — Other (0.7 ) 1.9 (3.2 ) Income Tax Expense $ 5.0 $ 50.1 $ 54.4 Effective Income Tax Rate 5.7 % 41.0 % 35.2 % SWEPCo Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 152.2 $ 137.5 $ 169.7 Less: Equity Earnings – Dolet Hills (2.7 ) — — Income Tax Expense 20.4 48.1 52.1 Pretax Income $ 169.9 $ 185.6 $ 221.8 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 35.7 $ 65.0 $ 77.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.4 1.9 3.2 Depletion (3.2 ) (5.7 ) (5.5 ) State and Local Income Taxes, Net 3.2 (2.3 ) (14.7 ) AFUDC (1.3 ) (0.9 ) (3.9 ) Tax Adjustments — (9.9 ) (0.9 ) Tax Reform Adjustments — (0.4 ) — Tax Reform Excess ADIT Reversal (16.0 ) — — Other (1.4 ) 0.4 (3.7 ) Income Tax Expense $ 20.4 $ 48.1 $ 52.1 Effective Income Tax Rate 12.0 % 25.9 % 23.5 % 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, 2018 2017 (in millions) Deferred Tax Assets $ 2,750.8 $ 3,504.6 Deferred Tax Liabilities (9,837.3 ) (10,318.5 ) Net Deferred Tax Liabilities $ (7,086.5 ) $ (6,813.9 ) Property Related Temporary Differences $ (6,224.8 ) $ (5,680.6 ) Amounts Due to Customers for Future Federal Income Taxes 1,117.1 1,064.8 Deferred State Income Taxes (a) (859.9 ) (1,124.4 ) Securitized Assets (186.6 ) (257.7 ) Regulatory Assets (454.1 ) (500.3 ) Deferred Income Taxes on Other Comprehensive Loss 32.0 25.7 Accrued Nuclear Decommissioning (453.7 ) (457.0 ) Net Operating Loss Carryforward 78.3 86.6 Tax Credit Carryforward 113.7 174.7 Investment in Partnership (300.5 ) (222.0 ) All Other, Net 52.0 76.3 Net Deferred Tax Liabilities $ (7,086.5 ) $ (6,813.9 ) (a) In 2018, AEP recorded a $233 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. AEP Texas December 31, 2018 2017 (in millions) Deferred Tax Assets $ 208.1 $ 221.0 Deferred Tax Liabilities (1,121.2 ) (1,134.1 ) Net Deferred Tax Liabilities $ (913.1 ) $ (913.1 ) Property Related Temporary Differences $ (836.3 ) $ (791.5 ) Amounts Due to Customers for Future Federal Income Taxes 140.6 140.9 Deferred State Income Taxes (27.1 ) (27.5 ) Regulatory Assets (53.9 ) (36.4 ) Securitized Transition Assets (134.7 ) (190.5 ) Deferred Income Taxes on Other Comprehensive Loss 4.0 4.1 Deferred Revenues 4.6 10.9 All Other, Net (10.3 ) (23.1 ) Net Deferred Tax Liabilities $ (913.1 ) $ (913.1 ) AEPTCo December 31, 2018 2017 (a) (in millions) Deferred Tax Assets $ 142.9 $ 163.0 Deferred Tax Liabilities (847.3 ) (763.4 ) Net Deferred Tax Liabilities $ (704.4 ) $ (600.4 ) Property Related Temporary Differences $ (755.0 ) $ (653.4 ) Amounts Due to Customers for Future Federal Income Taxes 101.6 89.7 Deferred State Income Taxes (b) (51.9 ) (77.4 ) Deferred Federal Income Taxes on Deferred State Income Taxes — 16.3 Net Operating Loss Carryforward 13.4 16.8 Tax Credit Carryforward — 0.3 All Other, Net (12.5 ) 7.3 Net Deferred Tax Liabilities $ (704.4 ) $ (600.4 ) (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. (b) In 2018, AEPTCo recorded a $21 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. APCo December 31, 2018 2017 (in millions) Deferred Tax Assets $ 475.2 $ 614.4 Deferred Tax Liabilities (2,101.0 ) (2,180.1 ) Net Deferred Tax Liabilities $ (1,625.8 ) $ (1,565.7 ) Property Related Temporary Differences $ (1,393.6 ) $ (1,308.2 ) Amounts Due to Customers for Future Federal Income Taxes 224.2 228.0 Deferred State Income Taxes (a) (280.3 ) (335.7 ) Regulatory Assets (73.8 ) (83.9 ) Securitized Assets (54.3 ) (59.3 ) Deferred Income Taxes on Other Comprehensive Loss 1.3 (0.4 ) Tax Credit Carryforward 0.2 16.6 All Other, Net (49.5 ) (22.8 ) Net Deferred Tax Liabilities $ (1,625.8 ) $ (1,565.7 ) (a) In 2018, APCo recorded a $51 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. I&M December 31, 2018 2017 (in millions) Deferred Tax Assets $ 771.6 $ 1,096.4 Deferred Tax Liabilities (1,719.6 ) (2,050.2 ) Net Deferred Tax Liabilities $ (948.0 ) $ (953.8 ) Property Related Temporary Differences $ (445.0 ) $ (403.0 ) Amounts Due to Customers for Future Federal Income Taxes 142.0 137.6 Deferred State Income Taxes (a) (139.7 ) (180.6 ) Deferred Income Taxes on Other Comprehensive Loss 3.7 3.9 Accrued Nuclear Decommissioning (453.7 ) (457.0 ) Regulatory Assets (31.9 ) (43.8 ) Net Operating Loss Carryforward 0.2 1.6 All Other, Net (23.6 ) (12.5 ) Net Deferred Tax Liabilities $ (948.0 ) $ (953.8 ) (a) In 2018, I&M recorded a $48 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. OPCo December 31, 2018 2017 (in millions) Deferred Tax Assets $ 209.0 $ 286.0 Deferred Tax Liabilities (972.3 ) (1,048.9 ) Net Deferred Tax Liabilities $ (763.3 ) $ (762.9 ) Property Related Temporary Differences $ (826.9 ) $ (761.2 ) Amounts Due to Customers for Future Federal Income Taxes 130.9 127.3 Deferred State Income Taxes (26.8 ) (41.7 ) Regulatory Assets (55.0 ) (107.7 ) Deferred Income Taxes on Other Comprehensive Loss (0.3 ) (0.6 ) Deferred Fuel and Purchased Power (1.6 ) (24.5 ) All Other, Net 16.4 45.5 Net Deferred Tax Liabilities $ (763.3 ) $ (762.9 ) PSO December 31, 2018 2017 (in millions) Deferred Tax Assets $ 229.6 $ 269.2 Deferred Tax Liabilities (837.4 ) (911.2 ) Net Deferred Tax Liabilities $ (607.8 ) $ (642.0 ) Property Related Temporary Differences $ (609.4 ) $ (623.8 ) Amounts Due to Customers for Future Federal Income Taxes 107.1 111.6 Deferred State Income Taxes (a) (103.8 ) (142.7 ) Regulatory Assets (32.3 ) (34.4 ) Deferred Income Taxes on Other Comprehensive Loss (0.6 ) (0.8 ) Deferred Federal Income Taxes on Deferred State Income Taxes — 33.5 Net Operating Loss Carryforward 16.4 23.1 Tax Credit Carryforward — 0.7 All Other, Net 14.8 (9.2 ) Net Deferred Tax Liabilities $ (607.8 ) $ (642.0 ) (a) In 2018, PSO recorded a $33 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. SWEPCo December 31, 2018 2017 (in millions) Deferred Tax Assets $ 317.4 $ 349.4 Deferred Tax Liabilities (1,220.2 ) (1,267.1 ) Net Deferred Tax Liabilities $ (902.8 ) $ (917.7 ) Property Related Temporary Differences $ (929.1 ) $ (908.8 ) Amounts Due to Customers for Future Federal Income Taxes 145.8 135.8 Deferred State Income Taxes (a) (156.0 ) (189.2 ) Regulatory Assets (30.8 ) (30.8 ) Deferred Income Taxes on Other Comprehensive Loss 1.4 1.3 Capital/Impairment Loss - Turk Plant 15.8 17.4 Net Operating Loss Carryforward 36.2 38.7 Tax Credit Carryforward — 0.8 All Other, Net 13.9 17.1 Net Deferred Tax Liabilities $ (902.8 ) $ (917.7 ) (a) In 2018, SWEPCo recorded a $38 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. 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, the loss of the Parent and tax credits, 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. 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. Valuation allowance activity for the years ended December 31, 2018 and 2017 was immaterial. 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 utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015. In June 2018, AEP settled all outstanding issues under audit for tax years 2011-2015. As a result, the related $72 million unrecognized tax benefit was reversed in the second quarter of 2018. The Joint Committee approved the settlement in November 2018. The settlement did not materially impact the Registrants net income, cash flows or financial condition. The IRS examination of 2016 began in October 2018. AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2007. Net Income Tax Operating Loss Carryforward As of December 31, 2018, AEP, AEPTCo, I&M, PSO and SWEPCo have state net income tax operating loss carryforwards as indicated in the table below: State Net Income Tax Operating Loss Years of Company State/Municipality Carryforward Expiration (in millions) AEP Arkansas $ 67.8 2018 - 2023 AEP Kentucky 130.4 2025 - 2037 AEP Louisiana 517.3 2030 - 2038 AEP Oklahoma 644.2 2032 - 2037 AEP Tennessee 28.6 2025 - 2033 AEP Virginia 22.8 2030 - 2038 AEP West Virginia 5.1 2029 - 2037 AEP Ohio Municipal 226.5 2019 - 2023 AEPTCo Oklahoma 264.0 2032 - 2037 AEPTCo Ohio Municipal 43.6 2019 - 2023 I&M West Virginia 3.8 2032 - 2037 PSO Oklahoma 348.8 2034 - 2037 SWEPCo Arkansas 67.1 2021 - 2023 SWEPCo Louisiana 504.9 2032 - 2037 As of December 31, 2018, AEP and AEPTCo have recorded valuation allowances of $5 million and $1 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. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2017, 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2018, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2037 through 2038 . 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 $ 113.7 $ 100.9 $ 34.2 $ — APCo 0.2 — — — I&M 0.9 — — — PSO — — 34.2 — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. Uncertain Tax Positions The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2018 $ 86.6 $ (0.8 ) $ — $ — $ 3.2 $ 6.9 $ — $ (0.8 ) Increase – Tax Positions Taken During a Prior Period 0.1 — — — — — — — Decrease – Tax Positions Taken During a Prior Period — — — — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Settlements with Taxing Authorities (71.0 ) — — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (1.1 ) — — — — — — — Balance as of December 31, 2018 $ 14.6 $ (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, 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 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2018 2017 2016 (in millions) AEP $ 11.6 $ 10.5 $ 15.8 AEP Texas (0.7 ) (0.5 ) 4.2 AEPTCo — — — APCo — — — I&M 2.6 2.1 2.5 OPCo 5.4 4.5 4.4 PSO — — 0.1 SWEPCo (0.6 ) (0.5 ) 0.8 State Tax Legislation In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution e

Leases

Leases	12 Months Ended
	Dec. 31, 2018
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 17 years and require payments of related property taxes, maintenance and operating costs. Many of the leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Lease rentals for both operating and capital leases are generally charged to 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 were as follows: Year Ended December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 245.0 $ 13.6 $ 2.7 $ 18.2 $ 89.2 $ 10.7 $ 5.7 $ 6.5 Amortization of Capital Leases 62.4 4.8 0.1 7.0 6.6 3.9 3.2 11.2 Interest on Capital Leases 16.4 1.2 — 3.0 3.3 0.5 0.4 3.2 Total Lease Rental Costs $ 323.8 $ 19.6 $ 2.8 $ 28.2 $ 99.1 $ 15.1 $ 9.3 $ 20.9 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 (a) Amounts include lease expenses related to Desert Sky and Trent that were classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for the year ended December 31, 2016. See Note 7 - Dispositions and Impairments 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, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 131.3 $ — $ — $ 38.7 $ 27.0 $ — $ 2.6 $ 34.3 Other Property, Plant and Equipment 373.9 38.8 0.2 17.3 33.3 20.4 17.6 119.8 Total Property, Plant and Equipment 505.2 38.8 0.2 56.0 60.3 20.4 20.2 154.1 Accumulated Amortization 226.4 10.3 0.1 16.2 21.6 8.3 7.9 99.9 Net Property, Plant and Equipment Under Capital Leases $ 278.8 $ 28.5 $ 0.1 $ 39.8 $ 38.7 $ 12.1 $ 12.3 $ 54.2 Obligations Under Capital Leases: Noncurrent Liability $ 233.5 $ 24.0 $ — $ 33.7 $ 33.4 $ 9.2 $ 9.5 $ 50.6 Liability Due Within One Year 55.5 4.5 0.1 6.1 5.3 2.9 2.8 10.2 Total Obligations Under Capital Leases $ 289.0 $ 28.5 $ 0.1 $ 39.8 $ 38.7 $ 12.1 $ 12.3 $ 60.8 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 Future minimum lease payments consisted of the following as of December 31, 2018 : Capital Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 70.8 $ 5.8 $ 0.1 $ 9.0 $ 8.2 $ 3.3 $ 3.4 $ 13.1 2020 60.2 5.3 — 8.0 7.2 2.7 2.6 11.5 2021 51.7 4.7 — 7.3 6.6 2.3 2.0 10.5 2022 43.8 4.2 — 6.8 6.1 1.7 1.6 9.4 2023 35.5 3.7 — 6.3 5.7 1.2 1.4 8.6 Later Years 90.2 10.1 — 13.3 21.7 2.8 3.3 18.7 Total Future Minimum Lease Payments 352.2 33.8 0.1 50.7 55.5 14.0 14.3 71.8 Less Estimated Interest Element 63.2 5.3 — 10.9 16.8 1.9 2.0 11.0 Estimated Present Value of Future Minimum Lease Payments $ 289.0 $ 28.5 $ 0.1 $ 39.8 $ 38.7 $ 12.1 $ 12.3 $ 60.8 Noncancelable Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 259.6 $ 15.1 $ 2.3 $ 17.6 $ 92.6 $ 14.5 $ 6.5 $ 7.4 2020 250.1 14.1 1.8 16.5 89.3 13.2 6.0 7.2 2021 232.7 13.2 1.0 13.9 84.8 10.9 5.0 6.7 2022 222.5 12.2 0.5 12.8 83.8 10.0 4.6 6.1 2023 58.3 10.8 0.1 9.9 6.5 8.8 4.1 5.0 Later Years 165.2 28.4 — 20.5 19.5 31.7 10.7 11.7 Total Future Minimum Lease Payments $ 1,188.4 $ 93.8 $ 5.7 $ 91.2 $ 376.5 $ 89.1 $ 36.9 $ 44.1 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 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 amount guaranteed. As of December 31, 2018 , 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 was as follows: Company Maximum Potential Loss (in millions) AEP $ 47.7 AEP Texas 10.8 APCo 8.8 I&M 3.7 OPCo 7.9 PSO 3.8 SWEPCo 4.3 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, 2018 were as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 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 $ 590.6 $ 295.3 (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 2003, AEP Transportation LLC, a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. In 2008, AEP Transportation LLC assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo exercised all renewal options for the maximum lease term. The future minimum lease obligations were $6 million and $7 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2018 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the remaining five-year 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 is equal to 77% of the projected fair value of the equipment. I&M and SWEPCo assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee were $5 million and $5 million for I&M and SWEPCo, respectively, as of December 31, 2018 , 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 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain 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, 2018 , the maximum potential amount of future payments required under the guaranteed leases was $44 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, 2018 , AEP’s boat and barge lease guarantee liability was $5 million , of which $1 million was recorded in Other Current Liabilities and $4 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. In January 2018, S&P Global Inc. downgraded the ratings of the nonaffiliated party and set their outlook to negative. In April 2018, Moody’s Investors Service Inc. also downgraded their rating and set their outlook to negative. It is reasonably possible that enforcement of AEP’s liability for future payments under these leases could be exercised, which could reduce future net income and cash flows and impact financial condition.

Financing Activities

Financing Activities	12 Months Ended
	Dec. 31, 2018
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Common Stock (Applies to AEP) The following table is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury 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 Issued 1,239,392 — Treasury Stock Reissued — (886 ) (a) Balance, December 31, 2018 513,450,036 20,204,160 (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, 2018 2018 2017 2018 2017 AEP (in millions) Senior Unsecured Notes 2018-2048 4.36% 2.15%-8.13% 2.15%-8.13% $ 18,903.3 $ 16,478.3 Pollution Control Bonds (a) 2018-2038 (b) 3.14% 1.60%-6.30% 1.54%-6.30% 1,643.8 1,621.7 Notes Payable – Nonaffiliated (c) 2019-2032 3.95% 3.20%-6.37% 2.03%-6.37% 204.7 260.8 Securitization Bonds 2018-2028 (d) 3.65% 1.98%-5.31% 1.98%-5.31% 1,111.4 1,416.5 Spent Nuclear Fuel Obligation (e) 273.6 268.6 Other Long-term Debt 2018-2059 3.72% 1.15%-13.718% 1.15%-13.718% 1,209.9 1,127.4 Total Long-term Debt Outstanding $ 23,346.7 $ 21,173.3 AEP Texas Senior Unsecured Notes 2018-2047 4.06% 2.40%-6.76% 2.40%-6.76% $ 2,398.4 $ 1,932.2 Pollution Control Bonds 2020-2030 4.39% 1.75%-6.30% 1.75%-6.30% 490.9 490.5 Securitization Bonds 2018-2024 (d) 3.95% 1.98%-5.31% 1.98%-5.31% 791.2 1,026.1 Other Long-term Debt 2019-2059 3.94% 3.94%-4.50% 2.75%-4.50% 200.8 200.5 Total Long-term Debt Outstanding $ 3,881.3 $ 3,649.3 AEPTCo Senior Unsecured Notes 2018-2048 3.92% 2.68%-5.52% 2.68%-5.52% $ 2,823.0 $ 2,550.4 Total Long-term Debt Outstanding $ 2,823.0 $ 2,550.4 APCo Senior Unsecured Notes 2021-2045 5.20% 3.30%-7.00% 3.30%-7.00% $ 3,047.3 $ 3,045.1 Pollution Control Bonds (a) 2018-2038 (b) 2.64% 1.70%-5.38% 1.625%-5.38% 616.0 512.2 Securitization Bonds 2023-2028 (d) 3.06% 2.008%-3.772% 2.008%-3.772% 272.3 295.9 Other Long-term Debt 2019-2026 3.91% 3.74%-13.718% 2.73%-13.718% 127.0 126.9 Total Long-term Debt Outstanding $ 4,062.6 $ 3,980.1 I&M Senior Unsecured Notes 2019-2048 4.38% 3.20%-6.05% 3.20%-7.00% $ 2,149.0 $ 1,809.0 Pollution Control Bonds (a) 2018-2025 (b) 2.49% 1.81%-3.05% 1.75%-2.75% 264.5 264.6 Notes Payable – Nonaffiliated (c) 2019-2022 3.30% 3.20%-3.38% 2.03%-2.19% 135.8 188.6 Spent Nuclear Fuel Obligation (e) 273.6 268.6 Other Long-term Debt 2018-2025 3.80% 3.66%-6.00% 2.82%-6.00% 212.5 214.3 Total Long-term Debt Outstanding $ 3,035.4 $ 2,745.1 OPCo Senior Unsecured Notes 2018-2048 5.52% 4.15%-6.60% 5.375%-6.60% $ 1,635.5 $ 1,591.4 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.3 Securitization Bonds 2019 (d) 2.049% 2.049% 2.049% 47.8 94.5 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.0 1.1 Total Long-term Debt Outstanding $ 1,716.6 $ 1,719.3 PSO Senior Unsecured Notes 2019-2046 4.80% 3.05%-6.625% 3.05%-6.625% $ 1,144.9 $ 1,144.1 Pollution Control Bonds 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2019-2027 3.70% 3.00%-3.72% 2.584%-3.00% 129.5 129.8 Total Long-term Debt Outstanding $ 1,287.0 $ 1,286.5 SWEPCo Senior Unsecured Notes 2018-2048 4.04% 2.75%-6.20% 2.75%-6.45% $ 2,427.0 $ 2,110.7 Pollution Control Bonds 2018-2019 1.60% 1.60% 1.60%-4.95% 53.5 135.1 Notes Payable – Nonaffiliated (c) 2024-2032 5.23% 4.58%-6.37% 4.58%-6.37% 68.9 72.1 Other Long-term Debt 2020-2028 4.03% 3.75%-4.68% 2.925%-4.28% 164.0 124.0 Total Long-term Debt Outstanding $ 2,713.4 $ 2,441.9 (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 SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information. As of December 31, 2018 , outstanding long-term debt was payable as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 1,698.5 $ 501.1 $ 85.0 $ 430.7 $ 155.4 $ 47.9 $ 375.5 $ 59.7 2020 1,508.3 377.7 — 90.3 41.6 0.1 13.2 121.2 2021 1,961.5 66.2 50.0 393.0 256.4 500.1 250.5 6.2 2022 1,668.4 493.0 104.0 230.4 7.0 0.1 0.5 281.2 2023 539.6 195.0 60.0 26.6 252.4 0.1 0.5 6.2 After 2023 16,150.9 2,275.5 2,551.0 2,924.4 2,351.5 1,182.8 652.0 2,262.9 Principal Amount 23,527.2 3,908.5 2,850.0 4,095.4 3,064.3 1,731.1 1,292.2 2,737.4 Unamortized Discount, Net and Debt Issuance Costs (180.5 ) (27.2 ) (27.0 ) (32.8 ) (28.9 ) (14.5 ) (5.2 ) (24.0 ) Total Long-term Debt Outstanding $ 23,346.7 $ 3,881.3 $ 2,823.0 $ 4,062.6 $ 3,035.4 $ 1,716.6 $ 1,287.0 $ 2,713.4 As of December 31, 2018 , trustees held, on behalf of AEP, $574 million of their reacquired Pollution Control Bonds. Of this total, $345 million related to OPCo. Long-term Debt Subsequent Events In January and February 2019 , I&M retired $15 million and $2 million , respectively, of Notes Payable related to DCC Fuel. In January and February 2019 , Transource Energy issued $3 million and $3 million , respectively, of variable rate Other Long-term Debt due in 2020 . In January 2019 , AEP Texas retired $104 million of Securitization Bonds. In January 2019 , OPCo retired $23 million of Securitization Bonds. In January 2019 , SWEPCo retired $54 million of 1.60% Pollution Control Bonds due in 2019 . In February 2019 , APCo retired $12 million of Securitization Bonds. 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, 2018 . The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreement. 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. However, the Federal Power Act creates a reserve on retained earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain 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, 2018 , 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 $12.4 billion . The Federal Power Act restriction limits the ability of the AEP subsidiaries owning hydroelectric generation to pay dividends out of retained earnings. Additionally, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2018 , the amount of any such restrictions were as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Restricted Retained Earnings $ 1,591.4 (a) $ 353.7 $ — $ 17.6 $ 454.1 $ — $ 152.7 $ 526.4 (a) Includes the restrictions of consolidated and non-consolidated 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, 2018 , AEP had $7.7 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.3 billion , $1.2 billion and $1.1 billion of dividends to common shareholders for the years ended December 31, 2018 , 2017 and 2016 , 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 funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. As of December 31, 2018 , AEP had a $4 billion revolving credit facility to support its commercial paper program. The commercial paper program for the year ended 2018 , had a weighted-average interest rate of 2.33% and a maximum amount outstanding of $2.3 billion . AEP’s outstanding short-term debt was as follows: December 31, 2018 2017 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 2.16 % $ 718.0 1.22 % AEP Commercial Paper 1,160.0 2.96 % 898.6 1.85 % SWEPCo Notes Payable — — % 22.0 2.92 % Total Short-term Debt $ 1,910.0 $ 1,638.6 (a) Weighted-average interest 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, 2018 and 2017 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits are described in the following tables: Year Ended December 31, 2018 : 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, 2018 Limit (in millions) AEP Texas $ 390.6 $ 106.9 $ 176.0 $ 47.1 $ (216.0 ) $ 500.0 AEPTCo 371.3 276.4 177.9 58.4 35.8 795.0 (a) APCo 295.5 23.7 175.3 23.3 (182.6 ) 600.0 I&M 322.1 657.8 255.5 110.7 11.6 500.0 OPCo 270.8 225.0 167.8 189.4 (114.1 ) 500.0 PSO 193.7 31.8 104.5 12.9 (105.5 ) 300.0 SWEPCo 200.1 533.7 143.2 268.1 81.4 350.0 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 (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 and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2018 and 2017 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, 2018 : Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2018 (in millions) AEP Texas $ 8.4 $ 8.1 $ 8.0 SWEPCo 2.0 2.0 2.0 Year Ended December 31, 2017 : Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2017 (in millions) AEP Texas $ 8.6 $ 8.3 $ 8.4 SWEPCo 2.0 2.0 2.0 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 and borrowings from AEP as of December 31, 2018 and 2017 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’ balance sheets. AEPTCo’s direct financing activities with AEP are described in the following tables: Year Ended December 31, 2018 : Maximum Maximum Average Average Borrowings From Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2018 December 31, 2018 Borrowing Limit (in millions) $ 1.2 $ 104.7 $ 1.1 $ 49.8 $ 1.2 $ 16.9 $ 75.0 (a) Year Ended December 31, 2017 : Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2017 December 31, 2017 Borrowing Limit (in millions) $ 4.1 $ 151.9 $ 1.1 $ 39.3 $ 1.1 $ 22.5 $ 75.0 (a) (a) 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 are summarized in the following table: Years Ended December 31, 2018 2017 2016 Maximum Interest Rate 2.97 % 1.85 % 1.02 % Minimum Interest Rate 1.81 % 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for the Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for the Years Ended December 31, Company 2018 2017 2016 2018 2017 2016 AEP Texas 2.26 % 1.29 % 0.88 % 2.29 % 1.26 % 0.72 % AEPTCo 2.27 % 1.36 % 0.85 % 2.10 % 1.27 % 0.83 % APCo 2.26 % 1.28 % 0.80 % 2.21 % 1.29 % 0.82 % I&M 2.16 % 1.27 % 0.80 % 2.08 % 1.29 % 0.80 % OPCo 2.18 % 1.37 % 0.85 % 2.47 % 0.98 % 0.74 % PSO 2.27 % 1.32 % 0.96 % 1.98 % — % 0.83 % SWEPCo 2.31 % 1.28 % 0.79 % 2.00 % 0.98 % 0.90 % 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, 2018 : 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 — % — % 2.97 % 1.83 % — % 2.36 % SWEPCo — % — % 2.97 % 1.83 % — % 2.36 % 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 % 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, 2018 : 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 2.97 % 1.76 % 2.97 % 1.76 % 2.36 % 2.36 % 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 % 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, 2018 , 2017 and 2016 . Credit Facilities See “Letters of Credit” section of Note 6 for additional information. 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 includes a $125 million and a $625 million facility which expire in July 2020 and 2021, respectively. Accounts receivable information for AEP Credit was as follows: Years Ended December 31, 2018 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 2.16 % 1.22 % 0.70 % Net Uncollectible Accounts Receivable Written Off $ 27.6 $ 23.4 $ 23.7 December 31, 2018 2017 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 972.5 $ 925.5 Short-term – Securitized Debt of Receivables 750.0 718.0 Delinquent Securitized Accounts Receivable 50.3 41.1 Bad Debt Reserves Related to Securitization 27.5 28.7 Unbilled Receivables Related to Securitization 281.4 303.2 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 were: December 31, Company 2018 2017 (in millions) APCo $ 133.3 $ 136.2 I&M 152.9 136.5 OPCo 395.2 367.4 PSO 109.7 115.1 SWEPCo 150.3 138.2 The fees paid to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 7.0 $ 5.6 $ 6.7 I&M 9.2 6.7 7.1 OPCo 26.3 21.7 28.9 PSO 7.9 7.0 6.2 SWEPCo 8.9 7.2 6.9 The proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 1,421.0 $ 1,372.8 $ 1,412.5 I&M 1,843.0 1,612.9 1,596.2 OPCo 2,674.5 2,339.0 2,633.0 PSO 1,484.6 1,337.0 1,269.3 SWEPCo 1,736.1 1,563.4 1,531.7

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2018
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, 2018 , 8,194,046 shares remained available for issuance under the 2015 LTIP. 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 from 2017 on 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 that participants realize. 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 sheets. 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 sheets and is adjusted for changes in value. Performance units settled in shares are recorded as mezzanine equity on the balance sheets 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 does not 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. The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP career shares for the years ended December 31, 2018 , 2017 and 2016 as follows: Years Ended December 31, Performance Units 2018 2017 2016 Awarded Units (in thousands) (a) 581.4 590.7 597.4 Weighted Average Unit Fair Value at Grant Date $ 67.21 $ 69.78 $ 62.77 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2018 2017 2016 Awarded Units (in thousands) (b) 80.2 74.6 89.2 Weighted Average Fair Value at Grant Date $ 70.58 $ 72.35 $ 63.83 Vesting Period (in years) (c) (c) (c) (a) Awarded units in 2018 and 2017 were mezzanine equity awards and awarded units in 2016 were liability awards. (b) Awarded dividends in 2018 and 2017 were a mix of equity awards and liability awards, and all awarded dividends in 2016 were liability awards. (c) 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. Performance scores and final awards are determined and approved by the HR Committee in accordance with the pre-established performance measures within approximately one 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 and (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, 2018 , 2017 and 2016 were as follows: Years Ended December 31, Performance Units 2018 2017 2016 Certified Performance Score 136.7 % 164.8 % 163.9 % Performance Units Earned 820,780 956,055 1,111,966 Performance Units Mandatorily Deferred as AEP Career Shares 11,248 20,213 9,963 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 56,826 47,177 51,684 Performance Units to be Settled in Cash 752,706 888,665 1,050,319 The settlements for the years ended December 31, 2018 , 2017 and 2016 were as follows: Years Ended December 31, Performance Units and AEP Career Shares 2018 2017 2016 (in millions) Cash Settlements for Performance Units $ 66.9 $ 64.9 $ 62.7 Cash Settlements for Career Share Distributions — — 9.1 AEP Common Stock Settlements for Career Share Distributions 5.1 0.4 — A summary of the status of AEP’s nonvested Performance Units as of December 31, 2018 and changes during the year ended December 31, 2018 were as follows: Nonvested Performance Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2018 587.5 $ 64.48 Granted 617.3 67.43 Vested — — Forfeited (33.5 ) 65.50 Nonvested as of December 31, 2018 1,171.3 66.01 Monte Carlo Valuation AEP engages a third party for a Monte Carlo valuation to calculate half of the fair value for the performance units awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. The Assumptions used in the Monte Carlo valuations for the years ended December 31, 2018 and 2017 were as follows: Years Ended December 31, Monte Carlo Valuation 2018 2017 Valuation Period (in years) (a) 2.87 2.86 Expected Volatility Minimum 14.77 % 15.65 % Expected Volatility Maximum 26.72 % 27.19 % Expected Volatility Average 17.90 % 19.07 % Dividend Rate (b) — % — % Risk Free Rate 2.34 % 1.44 % (a) Period from award date to vesting date. (b) Equivalent to reinvesting dividends. 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 40 months from the grant date. The HR Committee awarded RSUs, including additional units awarded as dividends, for the years ended December 31, 2018 , 2017 and 2016 as follows: Years Ended December 31, Restricted Stock Units 2018 2017 2016 Awarded Units (in thousands) 260.0 255.8 242.0 Weighted Average Grant Date Fair Value $ 67.96 $ 65.26 $ 62.88 The total fair value and total intrinsic value of restricted stock units vested during the years ended December 31, 2018 , 2017 and 2016 were as follows: Years Ended December 31, Restricted Stock Units 2018 2017 2016 (in millions) Fair Value of Restricted Stock Units Vested $ 16.6 $ 16.1 $ 16.4 Intrinsic Value of Restricted Stock Units Vested (a) 19.2 20.0 21.0 (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, 2018 and changes during the year ended December 31, 2018 were as follows: Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2018 529.6 $ 62.13 Granted 260.0 67.96 Vested (277.5 ) 59.77 Forfeited (23.0 ) 64.84 Nonvested as of December 31, 2018 489.1 66.01 The total aggregate intrinsic value of nonvested RSUs as of December 31, 2018 was $37 million and the weighted average remaining contractual life was 1.65 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 the years ended December 31, 2018 , 2017 and 2016 , 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, 2018 , 2017 and 2016 as follows: Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2018 2017 2016 Awarded Units (in thousands) 11.4 14.8 19.1 Weighted Average Grant Date Fair Value $ 70.41 $ 70.79 $ 64.96 Share-based Compensation Plans For share-based payment arrangements the compensation cost, the actual tax benefit from the tax deductions for compensation cost recognized in income and the total compensation cost capitalized for the years ended December 31, 2018 , 2017 and 2016 were as follows: Years Ended December 31, Share-based Compensation Plans 2018 2017 2016 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 53.2 $ 79.5 $ 66.5 Actual Tax Benefit (b) 7.7 18.9 23.3 Total Compensation Cost Capitalized 19.7 26.4 20.8 (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 certain compensation expense in excess of $1 million for certain named executive officers. This will reduce the tax benefit going forward. As of December 31, 2018 , there was $60 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 1.4 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. 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, 2018
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) and Bridge Agreement (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo) Effective January 1, 2014, the FERC approved the following agreements. • Under the FERC approved PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The 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 that, amongst other things, addresses the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement. 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. Certain 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. With the transfer of OPCo’s generation assets to AGR in 2014, 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 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, 2018 , 2017 and 2016 : Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2018 Direct Sales to East Affiliates $ — $ — $ 133.2 $ 0.1 $ — $ — $ — Direct Sales to West Affiliates — — — — — — — Auction Sales to OPCo (a) — — 5.8 7.1 — — — Direct Sales to AEPEP 103.6 — — — — — — Transmission Agreement and Transmission Coordination Agreement Sales — 591.4 36.4 11.7 3.9 0.9 26.9 Other Revenues 1.6 7.5 6.0 3.2 17.1 4.5 1.5 Total Affiliated Revenues $ 105.2 $ 598.9 $ 181.4 $ 22.1 $ 21.0 $ 5.4 $ 28.4 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 — 559.6 (b) 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 $ 568.1 $ 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 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2018 , 2017 and 2016 . AEP Texas, AEPTCo, APCo and SWEPCo did not purchase any power from affiliates for the years ended December 31, 2018 , 2017 and 2016 . Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2018 Auction Purchases from AEPEP (a) $ — $ 79.7 $ — Auction Purchases from AEP Energy (a) — 41.0 — Auction Purchases from AEPSC (a) — 14.6 — Direct Purchases from AEGCo 237.9 — — Total Affiliated Purchases $ 237.9 $ 135.3 $ — 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 (a) Refer to the Ohio Auctions section below for further information regarding this amount. 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, 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, 2018 , 2017 and 2016 related to the TA: Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 128.3 $ 158.2 $ 103.2 I&M 91.4 103.8 53.0 OPCo 210.1 248.6 143.6 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA 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 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, 2018 , 2017 and 2016 : Years Ended December 31, Company 2018 2017 2016 (in millions) PSO $ 65.9 $ 56.0 $ 19.6 SWEPCo 10.5 6.6 (19.6 ) 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 and AEP Texas) Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $27 million , $30 million and $29 million for transmission services in 2018 , 2017 and 2016 , 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) In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agrees to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest ( 54.69% ) in the Oklaunion Power Station. AEPEP pays AEP Texas for the capacity and associated energy delivered to the delivery point, the sum of fuel, operation and maintenance, depreciation, capacity and all taxes other than federal income taxes applicable. A portion of the payment is fixed and is payable regardless of the level of output. There are no penalties if AEP Texas fails to maintain a minimum availability level or exceeds a maximum heat rate level. The PPA was approved by the FERC. AEP Texas recognizes revenues for the fuel, operations and maintenance and all other taxes as-billed. Revenue is recognized for the capacity and depreciation billed to AEPEP, on a straight-line basis over the term of the PPA as these represent the minimum payments due. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP expects to pay AEP Texas the full Property, Plant and Equipment balance through depreciation payments over the remaining period of operation of the plant, which is currently estimated to be September 2020. AEP Texas recorded revenue of $104 million , $64 million and $74 million from AEPEP for the years ended December 31, 2018 , 2017 and 2016 , 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 a 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, 2018 , 2017 and 2016 , AEPTCo recorded the following costs in Other Operation expense related to these agreements: Years Ended December 31, Billing Company 2018 2017 2016 (in millions) I&M $ 2.2 $ 1.4 $ 0.8 KPCo 0.2 0.2 0.1 OPCo 2.9 2.4 2.3 PSO 0.3 0.3 0.2 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 AEGCo and KPCo, 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 were $12 million , $10 million and $13 million in 2018 , 2017 and 2016 , respectively. I&M recorded the cost of transloading services in Fuel on the balance sheets. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance costs in 2018 , 2017 and 2016 were as follows: Years Ended December 31, Company 2018 2017 2016 (in millions) I&M $ 1.5 $ 1.3 $ 1.7 PSO 0.7 0.5 0.6 SWEPCo 3.4 3.5 3.3 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 2018 2017 2016 (in millions) AEGCo $ 19.9 $ 15.3 $ 14.8 AGR — 0.1 0.3 APCo 35.1 37.2 36.9 KPCo 4.2 5.0 5.3 WPCo 4.2 5.0 4.8 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 2018 2017 2016 (in millions) AGR $ 1.6 $ 1.2 $ 2.0 I&M 2.4 2.7 2.9 KPCo 1.7 1.8 1.5 PSO 0.5 1.1 0.5 SWEPCo 0.7 0.8 0.9 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, 2018 , 2017 and 2016 : Sales Years Ended December 31, Company 2018 2017 2016 (in millions) AEP Texas $ 0.3 $ 0.2 $ 0.3 APCo 5.4 3.5 4.5 I&M 8.2 5.0 5.2 OPCo 10.7 2.9 1.9 PSO 1.0 1.5 7.5 SWEPCo 0.8 0.5 1.0 Purchases Years Ended December 31, Company 2018 2017 2016 (in millions) AEP Texas $ 0.1 $ 0.4 $ 0.7 AEPTCo 18.5 9.1 6.5 APCo 0.6 0.9 1.5 I&M 2.0 3.5 2.7 OPCo 2.8 1.6 1.7 PSO 1.3 0.2 3.2 SWEPCo 0.8 0.4 6.5 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, 2018
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, Transource Energy and Desert Sky and Trent. 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 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, 2018 , 2017 and 2016 were $152 million , $137 million and $162 million , respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. DCC Fuel 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, 2018 , 2017 and 2016 were $113 million , $136 million and $101 million , respectively. The leases were recorded as capital leases on I&M’s balance sheets 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 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 $791 million and $1 billion as of December 31, 2018 and 2017 , 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 $637 million and $870 million as of December 31, 2018 and 2017 , 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 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 $48 million and $95 million as of December 31, 2018 and 2017 , 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 $13 million and $38 million as of December 31, 2018 and 2017 , 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 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 $272 million and $296 million as of December 31, 2018 and 2017 , 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 $259 million and $282 million as of December 31, 2018 and 2017 , 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 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 . EIS AEP’s subsidiaries participate in one protected cell of EIS for approximately seven 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, 2018 , 2017 and 2016 was $34 million , $29 million and $28 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 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. Transource Energy’s activities consist of the development, construction and operation of FERC-regulated transmission assets in Missouri, West Virginia, Pennsylvania and Maryland. Transource Energy has a credit facility agreement where borrowings are loaned through intercompany lending agreements to its subsidiaries. The creditor to the agreement has no recourse to the general credit of AEP. Transource Energy’s credit facility agreement contains certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5% . For the years ended December 31, 2018 , 2017 and 2016 , AEP provided capital contributions to Transource Energy of $4 million , $5 million and $45 million , respectively. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. Desert Sky Wind Farm LLC and Trent Wind Farm LLC Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively “the LLCs”) were established for the purpose of repowering, owning and operating wind-powered electric energy generation facilities in Texas. In January 2018, AEP admitted a nonaffiliate as a member of the LLCs to own and repower Desert Sky and Trent. The nonaffiliate contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. The nonaffiliates’ contribution of $84 million was recorded as Net Property, Plant and Equipment on the balance sheets, which was the fair value as of the contribution date determined based on key input assumptions of the original cost of the full turbine sets and the discounted cash flow benefit associated with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. AEP owns 79.9% of the LLCs. As a result, management has concluded that the LLCs are VIEs and that AEP is the primary beneficiary based on its power to direct the activities that most significantly impact their economic performance. Also in January 2018, the LLCs entered into a forward PPA for the sale of power to AEPEP related to deliveries of electricity beginning January 1, 2021 for a 12 year period. Prior to the effective date of the PPA, the LLCs will sell power at market rates into ERCOT. AEP and the nonaffiliate will share tax attributes including production tax credits and cash distributions from the operation of the LLCs generally consistent with the ownership percentages. See the table below for the classification of the LLCs’ assets and liabilities on the balance sheets. AEP has a call right, which if exercised, would require the nonaffiliate to sell its noncontrolling interest in the LLCs to AEP. The call exercise period is for ninety days, beginning July 2020 for Trent Wind Farm LLC and August 2020 for Desert Sky Wind Farm LLC. The nonaffiliates’ interest in the LLCs is presented as Redeemable Noncontrolling Interest on the balance sheets. The nonaffiliate holds redemption rights, which if exercised, would require AEP to purchase the nonaffiliates’ noncontrolling interest in the LLCs. The redemption right exercise period is for ninety days, beginning July 2021 for Trent Wind Farm LLC and August 2021 for Desert Sky Wind Farm LLC. The exercise price for both the call and redemption right are determined using a discounted cash flow model with agreed input assumptions as well as potential updates to certain assumptions reasonably expected based on the actual results of the LLCs. As of December 31, 2018 , AEP recorded $69 million of Redeemable Noncontrolling Interest in Mezzanine Equity on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2018 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel AEP Texas Transition Funding OPCo APCo (in millions) ASSETS Current Assets $ 70.0 $ 77.6 $ 192.8 $ 29.5 $ 24.8 Net Property, Plant and Equipment 106.9 122.3 — — — Other Noncurrent Assets 98.5 58.4 683.5 (a) 24.2 (b) 261.8 (c) Total Assets $ 275.4 $ 258.3 $ 876.3 $ 53.7 $ 286.6 LIABILITIES AND EQUITY Current Liabilities $ 31.1 $ 77.1 $ 271.9 $ 48.5 $ 28.0 Noncurrent Liabilities 244.0 181.2 586.1 3.9 256.7 Equity 0.3 — 18.3 1.3 1.9 Total Liabilities and Equity $ 275.4 $ 258.3 $ 876.3 $ 53.7 $ 286.6 (a) Includes an intercompany item eliminated in consolidation of $47 million . (b) Includes an intercompany item eliminated in consolidation of $11 million . (c) Includes an intercompany item eliminated in consolidation of $3 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2018 Other Consolidated VIEs AEP Credit Protected Cell of EIS Transource Energy Desert Sky and Trent (in millions) ASSETS Current Assets $ 974.2 $ 177.8 $ 25.7 $ 6.8 Net Property, Plant and Equipment — — 380.3 348.5 Other Noncurrent Assets 6.3 0.1 1.9 — Total Assets $ 980.5 $ 177.9 $ 407.9 $ 355.3 LIABILITIES AND EQUITY Current Liabilities $ 923.5 $ 38.6 $ 19.9 $ 8.7 Noncurrent Liabilities 0.8 85.3 160.3 6.2 Equity 56.2 54.0 227.7 340.4 Total Liabilities and Equity $ 980.5 $ 177.9 $ 407.9 $ 355.3 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 $54 million . (b) Includes an intercompany item eliminated in consolidation of $33 million . (c) Includes an intercompany item eliminated in consolidation of $3 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 Non-Consolidated Significant Variable Interests DHLC 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, 2018 , 2017 and 2016 were $58 million , $61 million and $65 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, 2018 2017 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 14.5 14.5 11.8 11.8 SWEPCo’s Share of Obligations — 167.6 — 144.3 Total Investment in DHLC $ 22.1 $ 189.7 $ 19.4 $ 163.7 OVEC AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2018 , 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 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, 2018 and 2017 , OVEC’s outstanding indebtedness was approximately $1.4 billion and $1.4 billion , respectively. 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 for additional information. AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and its subsidiary holds a significant variable interest in OVEC. Power to control decision making that significantly impacts 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, 2018 2017 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) — 604.1 — 626.3 Total Investment in OVEC $ 4.4 $ 608.5 $ 4.4 $ 630.7 (a) Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $218 million , $109 million and $277 million as of December 31, 2018 and $226 million , $113 million and $287 million as of December 31, 2017 , respectively. Power purchased by the Registrant Subsidiaries from OVEC is included in Purchased Electricity for Resale on the statements of income and is shown in the table below: Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 100.4 $ 101.0 $ 88.0 I&M 50.2 50.5 44.0 OPCo 127.5 128.2 111.7 Potomac-Appalachian Transmission Highline, LLC (PATH) AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in 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 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 refunded $11.4 million in 2018, including carrying charges, related to the January 2017 order in its 2018 Projected Transmission Revenue Requirement. In January 2019, FERC issued an order on the PATH Companies’ formula rate compliance filing requesting additional information regarding certain additional costs that may be required to be refunded. AEP’s investment in PATH-WV was: December 31, 2018 2017 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 (1.4 ) (1.4 ) (2.0 ) (2.0 ) Total Investment in PATH-WV $ 17.4 $ 17.4 $ 16.8 $ 16.8 AEP’s investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows and impact financial condition. AEPSC 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 2018 2017 2016 (in millions) AEP Texas $ 184.3 $ 152.6 $ 142.3 AEPTCo 220.4 188.9 131.1 APCo 295.6 268.8 244.2 I&M 173.5 176.0 147.7 OPCo 214.9 195.7 181.1 PSO 121.5 114.7 111.0 SWEPCo 164.4 150.7 147.0 The carrying amount and classification of variable interest in AEPSC’s accounts payable were as follows: December 31, 2018 2017 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) AEP Texas $ 22.3 $ 22.3 $ 24.2 $ 24.2 AEPTCo 24.6 24.6 25.1 25.1 APCo 32.2 32.2 37.0 37.0 I&M 23.8 23.8 26.8 26.8 OPCo 23.9 23.9 27.4 27.4 PSO 13.2 13.2 18.7 18.7 SWEPCo 18.4 18.4 20.8 20.8 AEGCo AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1 and leases a 50% interest in Rockport Plant, Unit 2. 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, 2018 , 2017 and 2016 were $238 million , $224 million and $229 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2018 and 2017 was $20 million and $23 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. See “Rockport Lease” section of Note 13 for additional information.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 : December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 20,989.1 (a) $ — $ — $ 6,509.6 $ 4,887.2 $ — $ 1,577.0 $ 4,672.6 (a) Transmission 21,500.5 3,683.6 6,515.8 3,317.7 1,576.8 2,544.3 892.3 1,866.9 Distribution 21,192.8 4,043.2 — 3,989.4 2,249.7 4,942.3 2,572.8 2,178.6 Other 3,770.8 724.6 172.6 457.4 543.1 563.7 298.1 485.2 CWIP 4,352.6 (a) 836.0 1,578.3 490.2 465.3 432.1 94.0 194.7 (a) Less: Accumulated Depreciation 17,743.1 1,431.2 271.9 4,118.9 3,139.4 2,217.7 1,472.1 2,633.5 Total Regulated Property, Plant and Equipment - Net 54,062.7 7,856.2 7,994.8 10,645.4 6,582.7 6,264.7 3,962.1 6,764.5 Nonregulated Property, Plant and Equipment - Net 1,036.4 135.6 1.4 22.9 28.5 10.2 4.6 107.3 Total Property, Plant and Equipment - Net $ 55,099.1 $ 7,991.8 $ 7,996.2 $ 10,668.3 $ 6,611.2 $ 6,274.9 $ 3,966.7 $ 6,871.8 December 31, 2017 AEP AEP Texas AEPTCo (b) 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 5,319.7 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 3,224.8 457.6 125.4 399.5 552.3 485.5 282.0 416.8 CWIP 3,972.6 (a) 834.4 1,324.0 483.0 460.2 410.1 111.3 220.7 (a) Less: Accumulated Depreciation 16,906.7 1,399.4 152.6 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 6,616.5 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 $ 6,617.9 $ 10,245.1 $ 6,050.4 $ 5,766.8 $ 3,886.2 $ 6,632.0 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 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 2018 2017 2016 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% - 4.0% 20 - 132 2.3% - 3.7% 20 - 132 2.1% - 4.0% 35 - 132 Transmission 1.6% - 2.7% 15 - 81 1.6% - 2.7% 15 - 100 1.5% - 2.7% 15 - 100 Distribution 2.7% - 3.6% 7 - 78 2.7% - 3.7% 5 - 156 2.6% - 3.7% 7 - 156 Other 2.3% - 9.8% 5 - 75 2.3% - 9.2% 5 - 84 3.1% - 8.6% 5 - 84 AEP Texas 2018 2017 2016 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 1.7% 45 - 81 1.8% 45 - 81 Distribution 3.6% 7 - 70 3.6% 7 - 70 3.3% 7 - 70 Other 6.0% 5 - 50 8.7% 5 - 50 8.3% 5 - 50 AEPTCo 2018 2017 2016 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 1.9% 20 - 75 1.7% 20 - 100 1.6% 20 - 100 APCo 2018 2017 2016 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 - 112 3.1% 35 - 121 Transmission 1.6% 15 - 68 1.6% 15 - 68 1.5% 15 - 68 Distribution 3.6% 10 - 57 3.7% 10 - 57 3.7% 10 - 57 Other 7.4% 5 - 55 6.5% 5 - 55 6.0% 5 - 55 I&M 2018 2017 2016 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 3.4% 20 - 132 2.4% 20 - 132 2.4% 59 - 132 Transmission 1.8% 50 - 73 1.7% 50 - 75 1.7% 50 - 75 Distribution 3.1% 9 - 75 2.7% 10 - 70 2.8% 10 - 70 Other 8.9% 5 - 50 8.4% 5 - 45 8.6% 5 - 45 OPCo 2018 2017 2016 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 3.0% 14 - 65 2.8% 5 - 57 2.8% 7 - 57 Other 6.3% 5 - 50 6.2% 5 - 50 5.9% 5 - 50 PSO 2018 2017 2016 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 2.9% 35 - 75 2.4% 35 - 85 2.4% 35 - 85 Transmission 2.3% 45 - 75 2.2% 45 - 100 2.2% 45 - 100 Distribution 2.9% 15 - 78 2.7% 27 - 156 2.7% 27 - 156 Other 6.3% 5 - 64 7.4% 5 - 84 6.4% 5 - 84 SWEPCo 2018 2017 2016 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% 40 - 70 2.3% 40 - 70 2.1% 40 - 70 Transmission 2.2% 50 - 73 2.3% 50 - 73 2.2% 50 - 70 Distribution 2.7% 25 - 70 2.7% 25 - 70 2.6% 25 - 65 Other 8.0% 5 - 55 7.2% 5 - 55 6.8% 5 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP and AEP Texas. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo for 2018 , 2017 and 2016 . 2018 2017 2016 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 3.4% - 22.3% 15 - 59 2.4% - 5.1% 15 - 66 2.8% - 17.2% 40 - 66 Transmission 2.4% 40 0.2% 40 2.3% 43 - 55 Distribution 2.3% 40 2.3% 40 1.3% 40 - 50 Other 16.3% 5 - 50 (a) 12.1% 5 - 50 (a) 9.1% 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-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 (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, 2018 and 2017 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.66 billion and $1.30 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2018 and 2017 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $2.16 billion and $2.22 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 2018 and 2017 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2017 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates (a) ARO as of December 31, 2018 (in millions) AEP (b)(c)(d)(e) $ 2,005.7 $ 93.7 $ 0.8 $ (87.0 ) $ 342.3 (f) $ 2,355.5 AEP Texas (b)(e) 26.7 1.2 — (0.1 ) 0.1 27.9 APCo (b)(e) 125.0 6.6 — (17.3 ) 1.8 116.1 I&M (b)(c)(e) 1,321.8 58.7 — (0.2 ) 301.0 (f) 1,681.3 OPCo (e) 1.7 0.1 — — — 1.8 PSO (b)(e) 54.0 3.2 — (0.4 ) (9.9 ) 46.9 SWEPCo (b)(d)(e) 169.2 9.1 0.2 (11.7 ) 40.0 206.8 Company ARO as of December 31, 2016 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates (a) ARO as of December 31, 2017 (in millions) AEP (b)(c)(d)(e) $ 1,934.9 $ 90.9 $ 2.4 $ (104.5 ) $ 82.0 $ 2,005.7 AEP Texas (b)(e) 25.5 1.2 — (0.1 ) 0.1 26.7 APCo (b)(e) 127.1 7.0 — (21.7 ) 12.6 125.0 I&M (b)(c)(e) 1,258.1 55.9 — (0.1 ) 7.9 1,321.8 OPCo (e) 1.7 0.1 — (0.1 ) — 1.7 PSO (b)(e) 53.4 3.1 — (0.5 ) (2.0 ) 54.0 SWEPCo (b)(d)(e) 156.5 8.3 — (0.3 ) 4.7 169.2 (a) Primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs. (b) Includes ARO related to ash disposal facilities. (c) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.66 billion and $1.30 billion as of December 31, 2018 and 2017 , respectively. (d) Includes ARO related to Sabine and DHLC. (e) Includes ARO related to asbestos removal. (f) Revision for Cook Plant related to a new third-party study, which impacted the ARO liability for changes of estimated cash flows and application of a new discount rate. 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 2018 2017 2016 (in millions) AEP $ 132.5 $ 93.7 $ 113.2 AEP Texas 20.0 6.8 9.2 AEPTCo 70.6 49.0 (a) 52.3 APCo 13.2 9.2 11.7 I&M 11.9 11.1 15.3 OPCo 9.8 6.4 6.0 PSO 0.4 0.5 6.2 SWEPCo 6.0 2.4 11.0 (a) The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. 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 2018 2017 2016 (in millions) AEP $ 73.6 $ 48.6 $ 51.7 AEP Texas 18.4 6.8 5.9 AEPTCo 26.1 20.2 15.6 APCo 8.4 5.3 6.3 I&M 7.4 6.7 7.2 OPCo 5.8 3.8 3.3 PSO 0.9 1.1 3.4 SWEPCo 4.8 2.1 6.9 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, 2018 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a)(i)(j) Coal 83.5 % $ 16.4 $ 0.2 $ 2.4 Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % 336.2 5.1 209.6 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 375.1 1.6 88.9 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 591.3 16.6 418.0 Oklaunion Power Station (f) Coal 70.3 % 106.4 — 67.8 Turk Generating Plant (h)(k) Coal 73.3 % 1,590.5 1.1 197.5 Total $ 3,015.9 $ 24.6 $ 984.2 AEP Texas Oklaunion Power Station (f) Coal 54.7 % $ 352.1 $ 0.2 $ 218.6 I&M Rockport Generating Plant (c)(d)(e) Coal 50.0 % $ 1,108.7 $ 50.2 $ 514.1 PSO Oklaunion Power Station (f) Coal 15.6 % $ 106.4 $ — $ 67.8 SWEPCo Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % $ 336.2 $ 5.1 $ 209.6 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 375.1 1.6 88.9 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 591.3 16.6 418.0 Turk Generating Plant (h)(k) Coal 73.3 % 1,590.5 1.1 197.5 Total $ 2,893.1 $ 24.4 $ 914.0 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)(i)(j) Coal 83.5 % $ 2.1 $ 4.2 $ 0.1 Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % 343.1 5.3 214.2 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 589.8 7.8 406.3 Oklaunion Power Station (f) Coal 70.3 % 456.4 1.9 254.6 Turk Generating Plant (h)(k) Coal 73.3 % 1,580.4 3.2 166.6 Transmission (l) NA (b) 62.7 0.3 46.1 Total $ 3,399.3 $ 31.6 $ 1,169.5 AEP Texas Oklaunion Power Station (f) Coal 54.7 % $ 350.7 $ 1.3 $ 194.1 I&M Rockport Generating Plant (c)(d)(e) Coal 50.0 % $ 1,093.9 $ 28.2 $ 562.6 PSO Oklaunion Power Station (f) Coal 15.6 % $ 105.7 $ 0.6 $ 60.5 SWEPCo Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % $ 343.1 $ 5.3 $ 214.2 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 589.8 7.8 406.3 Turk Generating Plant (h)(k) Coal 73.3 % 1,580.4 3.2 166.6 Total $ 2,878.1 $ 25.2 $ 868.7 (a) Operated by AGR. (b) Varying percentages of ownership. (c) Operated by I&M. (d) 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 . (e) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (f) 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 . (g) Operated by CLECO, a non-affiliated company. (h) Operated by SWEPCo. (i) Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. See the “Impairments” section of Note 7 . (j) 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% . (k) 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 . (l) In accordance with the 2017 CCD Transmission Asset Exchange Agreement between OPCo, Dayton Power & Light Company and Duke Energy Ohio, Inc., the parties agreed to an exchange and transfer of jointly owned transmission assets in order to eliminate the joint ownership of these assets. The asset exchange closed on June 30, 2018, ending the joint ownership of these transmission assets. NA Not applicable.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2018
Goodwill	GOODWILL The disclosure in this note applies to AEP only. The changes in AEP’s carrying amount of goodwill for the years ended December 31, 2018 and 2017 by operating segment are as follows: Corporate and Other Generation & Marketing AEP Consolidated (in millions) 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 Impairment Losses — — — Balance as of December 31, 2018 $ 37.1 $ 15.4 $ 52.5 In the fourth quarters of 2018 and 2017 , 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.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2018
Revenue from Contracts with Customers	REVENUE FROM CONTRACTS WITH CUSTOMERS The disclosures in this note apply to all Registrants, unless indicated otherwise. Disaggregated Revenues from Contracts with Customers The table below represents AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue: Year Ended December 31, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 3,751.8 $ 2,189.2 $ — $ — $ — $ — $ 5,941.0 Commercial Revenues 2,206.4 1,273.4 — — — — 3,479.8 Industrial Revenues 2,190.2 494.5 — — — — 2,684.7 Other Retail Revenues 183.1 39.2 — — — — 222.3 Total Retail Revenues 8,331.5 3,996.3 — — — — 12,327.8 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 899.8 — — 544.4 — (226.0 ) 1,218.2 Transmission Revenues (b) 282.2 372.1 849.3 — — (737.1 ) 766.5 Marketing, Competitive Retail and Renewable Revenues — — — 1,353.0 — — 1,353.0 Total Wholesale and Competitive Retail Revenues 1,182.0 372.1 849.3 1,897.4 — (963.1 ) 3,337.7 Other Revenues from Contracts with Customers (c) 158.4 204.6 15.2 20.6 86.2 (32.0 ) 453.0 Total Revenues from Contracts with Customers 9,671.9 4,573.0 864.5 1,918.0 86.2 (995.1 ) 16,118.5 Other Revenues: Alternative Revenues (c) (15.9 ) (22.2 ) (60.4 ) — — 52.7 (45.8 ) Other Revenues (c) (10.5 ) 102.3 — 22.3 8.9 — 123.0 Total Other Revenues (26.4 ) 80.1 (60.4 ) 22.3 8.9 52.7 77.2 Total Revenues $ 9,645.5 $ 4,653.1 $ 804.1 $ 1,940.3 $ 95.1 $ (942.4 ) $ 16,195.7 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $121 million . The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $643 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries: Year Ended December 31, 2018 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 578.9 $ — $ 1,342.6 $ 730.0 $ 1,611.5 $ 659.0 $ 641.5 Commercial Revenues 436.2 — 582.4 490.3 835.7 404.4 491.9 Industrial Revenues 110.0 — 602.4 560.3 385.2 294.1 325.8 Other Retail Revenues 25.9 — 77.4 7.2 12.9 83.3 8.6 Total Retail Revenues 1,151.0 — 2,604.8 1,787.8 2,845.3 1,440.8 1,467.8 Wholesale Revenues: Generation Revenues (a) — — 250.4 470.5 — 36.3 216.8 Transmission Revenues (b) 313.4 816.9 82.7 23.1 58.5 40.2 108.4 Total Wholesale Revenues 313.4 816.9 333.1 493.6 58.5 76.5 325.2 Other Revenues from Contracts with Customers (c) 28.6 15.1 55.3 99.6 176.1 19.1 24.0 Total Revenues from Contracts with Customers 1,493.0 832.0 2,993.2 2,381.0 3,079.9 1,536.4 1,817.0 Other Revenues: Alternative Revenues (d) (1.3 ) (55.9 ) (23.8 ) (2.1 ) (20.8 ) 10.9 4.9 Other Revenues (d) 103.6 — (1.9 ) (8.2 ) 4.3 — — Total Other Revenues 102.3 (55.9 ) (25.7 ) (10.3 ) (16.5 ) 10.9 4.9 Total Revenues $ 1,595.3 $ 776.1 $ 2,967.5 $ 2,370.7 $ 3,063.4 $ 1,547.3 $ 1,821.9 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $134 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $646 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $70 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. Performance Obligations AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer. The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows: Retail Revenues AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements. Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days. Wholesale Revenues - Generation AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements. AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed. Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above. APCo has a performance obligation to supply wholesale electricity to KGPCo through a purchased power agreement. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above. Wholesale Revenues - Transmission AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM. AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT. APCo, I&M, KGPCo, KPCo, OPCo and WPCo (AEP East Companies) are parties to the Transmission Agreement (TA), which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the Transmission Coordination Agreement (TCA) by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. 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. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above. Marketing, Competitive Retail and Renewable Revenues AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation. Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly. Fixed Performance Obligations The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of December 31, 2018 . Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues. Company 2019 2020-2021 2022-2023 After 2024 Total (in millions) AEP $ 920.7 $ 173.7 $ 162.5 $ 266.3 $ 1,523.2 AEP Texas 332.8 — — — 332.8 AEPTCo 893.6 — — — 893.6 APCo 144.8 32.2 23.2 — 200.2 I&M 25.6 2.9 2.9 — 31.4 OPCo 65.4 — — — 65.4 PSO 17.3 — — — 17.3 SWEPCo 35.2 — — — 35.2 Contract Assets and Liabilities Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of December 31, 2018 . When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of December 31, 2018 . Accounts Receivable from Contracts with Customers Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of December 31, 2018 . See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information. The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets: Company December 31, 2018 January 1, 2018 (in millions) AEPTCo $ 58.6 $ 47.1 APCo 52.5 35.6 I&M 35.3 15.1 OPCo 46.1 26.1 PSO 12.4 6.1 SWEPCo 16.3 11.0 Contract Costs Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of December 31, 2018 .

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information	12 Months Ended
	Dec. 31, 2018
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 (a) APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2018 Total Revenues $ 4,048.3 $ 371.6 $ 191.7 $ 820.4 $ 576.8 $ 790.9 $ 336.8 $ 419.4 Operating Income 706.0 81.8 111.1 193.0 97.4 117.3 3.9 41.6 Net Income (Loss) 456.7 46.8 84.1 125.5 64.2 79.6 (7.2 ) 13.4 Earnings Attributable to Common Shareholders 454.4 NA NA NA NA NA NA 11.8 June 30, 2018 Total Revenues $ 4,013.2 $ 388.3 $ 200.1 $ 667.0 $ 589.7 $ 748.8 $ 398.3 $ 457.1 Operating Income 757.0 86.2 110.5 132.6 117.4 104.4 57.2 70.5 Net Income 530.1 46.5 82.0 77.4 94.7 68.8 36.6 38.7 Earnings Attributable to Common Shareholders 528.4 NA NA NA NA NA NA 37.6 September 30, 2018 Total Revenues $ 4,333.1 $ 433.4 $ 194.4 $ 762.0 $ 629.7 $ 778.3 $ 481.4 $ 535.3 Operating Income 668.6 94.0 97.0 49.8 110.2 79.9 78.5 127.1 Net Income 579.7 57.8 78.1 87.1 72.7 88.7 60.4 89.6 Earnings Attributable to Common Shareholders 577.6 NA NA NA NA NA NA 88.2 December 31, 2018 Total Revenues $ 3,801.1 $ 402.0 $ 189.9 $ 718.1 $ 574.5 $ 745.4 $ 330.8 $ 410.1 Operating Income 551.1 84.3 91.5 108.1 52.2 118.2 2.9 38.5 Net Income (Loss) 364.8 60.2 71.7 77.8 29.7 88.4 (6.6 ) 10.5 Earnings Attributable to Common Shareholders 363.4 NA NA NA NA NA NA 9.6 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 (b) 1,085.7 82.3 90.4 218.9 117.2 149.6 19.9 52.8 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 (b) 733.3 108.8 165.4 126.1 33.6 118.5 45.3 74.1 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 $ 165.6 $ 719.3 $ 557.7 $ 742.0 $ 442.8 $ 517.6 Operating Income (b) 975.1 128.8 93.6 171.7 113.6 153.4 85.9 136.0 Net Income 556.7 64.3 58.6 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 $ 159.2 $ 746.8 $ 535.7 $ 731.9 $ 335.6 $ 436.3 Operating Income (b) 730.9 96.2 83.5 173.6 82.8 144.2 20.4 41.1 Net Income 401.8 163.9 47.7 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. (a) The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1. (b) Amounts reflect the adoption of ASU 2017-07 “Compensation - Retirement Benefits”. See Note 2 - New Accounting Pronouncements for additional information. AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2018 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders (in millions) $ 454.4 $ 528.4 $ 577.6 $ 363.4 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 0.92 1.07 1.17 0.74 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 0.92 1.07 1.17 0.74 2017 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders (in millions) $ 592.2 $ 375.0 $ 544.7 $ 400.7 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.20 0.76 1.11 0.81 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.20 0.76 1.10 0.81 (a) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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 AEPTCo’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 (consolidated VIEs). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a consolidated VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated 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 on 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.
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 primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. 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 over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, 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 continuous 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 on the Registrant Subsidiaries’ statements of income 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 sheets. 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. 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 equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.
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 using 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 commission-approved plan to delay refunds or recoveries beyond a one year period. 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 SSO 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 incurred from 2009 through 2011, that continued to be recovered in rider rates were terminated in January 2019. 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 or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income. Retail and Wholesale Supply and Delivery of Electricity The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by the Registrants in the second quarter following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - 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. See Note 20 - Revenue from Contracts with Customers for additional information related to retail and wholesale revenues. Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities 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 from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized 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, 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. 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 approximately 18 months, 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 - Income Taxes for additional information related to Tax Reform. When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. AEP and subsidiaries apply the deferral methodology for the recognition of ITC. Deferred ITC is amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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, the loss of the Parent and tax credits, 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 (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill is not amortized. Management tests acquired goodwill at the reporting unit level for impairment at least annually at their estimated fair value. 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.
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, with the exception of the rate of compensation increase, 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 SNF 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. As of December 31, 2018 and 2017 , the fair value of securities on loan as part of the program was $241 million and $492 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2018 and 2017 . Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (Applies to AEP and I&M) Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF 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. With the adoption of ASU 2016-01, effective January 2018, available for sale classification only applies to investment in debt securities. Additionally, the adoption of ASU 2016-01 required changes in fair value of equity securities to be recognized in earnings. However, due to the regulatory treatment described below, this is not applicable for I&M’s trust fund securities. Other-than-temporary impairments for investments in debt 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, unrealized losses 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. 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 Spent Nuclear Fuel 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 non-owner 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, 2018 , 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 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. All AEP career shares are paid out in AEP common stock after the executive’s service with AEP ends. Performance units awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets. 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, 2018 , 2017 and 2016 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, 2018 , 2017 and 2016 , 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 - Stock-based Compensation for additional information.
Equity Method Investments	Equity Investment in Unconsolidated Affiliates (Applies to AEP and SWEPCo) AEP and SWEPCo include equity in earnings from equity method investments in Equity Earnings (Loss) of Unconsolidated Subsidiaries 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, 2018 and 2017 , AEP’s investment in ETT was $666 million and $664 million, respectively, which is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP’s equity earnings associated with ETT were $62 million and $82 million for the years ended December 31, 2018 and 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, 2018
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, with the exception of the rate of compensation increase, 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, 2018
Derivatives and Hedging	Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. 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, I&M and SWEPCo) 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. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. 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. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. 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. 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 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. 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.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2018
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, 2018
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 - Income Taxes for additional information related to Tax Reform. When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. AEP and subsidiaries apply the deferral methodology for the recognition of ITC. Deferred ITC is amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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, the loss of the Parent and tax credits, 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, 2018
Lease Policy	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, 2018
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2018 , 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 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. All AEP career shares are paid out in AEP common stock after the executive’s service with AEP ends. Performance units awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets. 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, 2018 , 2017 and 2016 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, 2018 , 2017 and 2016 , 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 - Stock-based Compensation 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, 2018 , 8,194,046 shares remained available for issuance under the 2015 LTIP. 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 1.4 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. 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 approved by the HR Committee in accordance with the pre-established performance measures within approximately one 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 and (b) three -year cumulative earnings per share measured relative to a target approved by the HR Committee. Monte Carlo Valuation AEP engages a third party for a Monte Carlo valuation to calculate half of the fair value for the performance units awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. 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 from 2017 on 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 that participants realize. 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 sheets. 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 sheets and is adjusted for changes in value. Performance units settled in shares are recorded as mezzanine equity on the balance sheets 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 does not 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.
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 40 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, 2018
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, 2018
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-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 S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Reconciliation of Cash, Cash Equivalents and Restricted Cash	December 31, 2018 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 234.1 $ 3.1 $ 4.2 $ 4.9 Restricted Cash 210.0 156.7 25.6 27.6 Total Cash, Cash Equivalents and Restricted Cash $ 444.1 $ 159.8 $ 29.8 $ 32.5 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
Significant Customers	Significant Customers of AEP Texas: Centrica, Just Energy, TXU Energy and Reliant Energy 2018 (b) 2017 (a)(b) 2016 (a) Percentage of Total Revenues 45 % 35 % 46 % Percentage of Accounts Receivable – Customers 35 % 31 % 42 % (a) TXU Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer. (b) 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 2018 2017 2016 Percentage of Total Revenues 77 % 80 % 77 % Percentage of Total Accounts Receivable 84 % 85 % (a) 86 % (a) Reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
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, 2018 2017 2016 (in millions, except per share data) $/share $/share $/share Income from Continuing Operations $ 1,931.3 $ 1,928.9 $ 620.5 Less: Net Income Attributable to Noncontrolling Interests 7.5 16.3 7.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,923.8 $ 1,912.6 $ 613.4 Weighted Average Number of Basic Shares Outstanding 492.8 $ 3.90 491.8 $ 3.89 491.5 $ 1.25 Weighted Average Dilutive Effect of Stock-Based Awards 1.0 — 0.8 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 493.8 $ 3.90 492.6 $ 3.88 491.7 $ 1.25
Supplementary Information	Years Ended December 31, Cash Flow Information 2018 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 939.3 $ 858.3 $ 848.5 Income Taxes (24.7 ) (1.1 ) 29.5 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 55.6 60.7 86.1 Construction Expenditures Included in Current Liabilities as of December 31, 1,120.4 1,330.8 858.0 Construction Expenditures Included in Noncurrent Liabilities as of December 31, — 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, 4.0 — 2.1 Noncash Contribution of Assets by Noncontrolling Interest 84.0 — — Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.2 2.6 0.7 2018 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,965.0 $ 262.2 $ 133.9 $ 428.1 $ 278.9 $ 232.6 $ 155.5 $ 237.0 Amortization of Certain Securitized Assets 287.9 240.0 — — — 47.9 — — Amortization of Regulatory Assets and Liabilities 33.7 (2.6 ) — 0.3 14.2 (20.8 ) 8.5 2.5 Total Depreciation and Amortization $ 2,286.6 $ 499.6 $ 133.9 $ 428.4 $ 293.1 $ 259.7 $ 164.0 $ 239.5 2017 Depreciation and Amortization AEP AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,709.1 $ 221.1 $ 95.7 $ 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 $ 95.7 $ 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 (a) Reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see “Revisions to Previously Issued Financial Statements” below.
Revision to Prior Year Income	Twelve Months Ended December 31, 2017 As Reported Adjustments As Adjusted (in millions) TOTAL REVENUES $ 723.2 $ (16.3 ) $ 706.9 EXPENSES Depreciation and Amortization 97.1 (1.4 ) 95.7 TOTAL EXPENSES 275.4 (1.4 ) 274.0 OPERATING INCOME 447.8 (14.9 ) 432.9 Other Income (Expense): Allowance for Equity Funds Used During Construction 52.3 (3.3 ) 49.0 Interest Expense (68.0 ) (2.2 ) (70.2 ) INCOME BEFORE INCOME TAX EXPENSE 433.3 (20.4 ) 412.9 Income Tax Expense 147.2 (5.0 ) 142.2 NET INCOME $ 286.1 $ (15.4 ) $ 270.7
Schedule of Error Corrections and Prior Period Adjustments	Twelve Months Ended December 31, 2017 As Reported Adjustments As Adjusted (in millions) OPERATING ACTIVITIES Net Income $ 286.1 $ (15.4 ) $ 270.7 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 97.1 (1.4 ) 95.7 Deferred Income Taxes 272.8 (1.3 ) 271.5 Allowance for Equity Funds Used During Construction (52.3 ) 3.3 (49.0 ) Property Taxes (15.6 ) (7.2 ) (22.8 ) Change in Other Noncurrent Assets 9.8 1.2 11.0 Change in Other Noncurrent Liabilities 27.3 0.2 27.5 Changes in Certain Components of Working Capital: Accounts Receivable, Net (34.5 ) 4.1 (30.4 ) Accounts Payable 9.8 13.2 23.0 Accrued Taxes, Net 13.0 3.3 16.3 Net Cash Flows from Operating Activities 604.8 — 604.8 INVESTING ACTIVITIES Net Cash Flows Used for Investing Activities (1,595.6 ) — (1,595.6 ) FINANCING ACTIVITIES Net Cash Flows from Financing Activities 990.8 — 990.8 Net Change in Cash and Cash Equivalents — — — Cash and Cash Equivalents at Beginning of Period — — — Cash and Cash Equivalents at End of Period $ — $ — $ — SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 61.2 $ 1.2 $ 62.4 Construction Expenditures Included in Current Liabilities as of December 31, 473.7 11.3 485.0 December 31, 2017 As Reported Adjustment As Adjusted CURRENT ASSETS (in millions) Accounts Receivable: Customers $ 19.1 $ (4.1 ) $ 15.0 Total Accounts Receivable 113.6 (4.1 ) 109.5 Accrued Tax Benefits 46.6 2.8 49.4 TOTAL CURRENT ASSETS 327.7 (1.3 ) 326.4 TRANSMISSION PROPERTY Transmission Property 5,336.1 (16.4 ) 5,319.7 Other Property, Plant and Equipment 131.4 (4.6 ) 126.8 Construction Work in Progress 1,312.7 11.3 1,324.0 Total Transmission Property 6,780.2 (9.7 ) 6,770.5 Accumulated Depreciation and Amortization 170.4 (17.8 ) 152.6 TOTAL TRANSMISSION PROPERTY – NET 6,609.8 8.1 6,617.9 OTHER NONCURRENT ASSETS Deferred Property Taxes 117.8 7.2 125.0 TOTAL OTHER NONCURRENT ASSETS 130.6 7.2 137.8 TOTAL ASSETS $ 7,068.1 $ 14.0 $ 7,082.1 CURRENT LIABILITIES Accounts Payable: General $ 473.2 $ 11.3 $ 484.5 Affiliated Companies 52.9 13.2 66.1 Accrued Taxes 225.4 6.1 231.5 TOTAL CURRENT LIABILITIES 836.3 30.6 866.9 NONCURRENT LIABILITIES Deferred Income Taxes 601.7 (1.3 ) 600.4 Regulatory Liabilities 493.7 0.1 493.8 TOTAL NONCURRENT LIABILITIES 3,626.5 (1.2 ) 3,625.3 TOTAL LIABILITIES 4,462.8 29.4 4,492.2 MEMBER’S EQUITY Retained Earnings 788.7 (15.4 ) 773.3 TOTAL MEMBER’S EQUITY 2,605.3 (15.4 ) 2,589.9 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 7,068.1 $ 14.0 $ 7,082.1

New Accounting Pronouncements N

New Accounting Pronouncements New Accounting Pronouncements (Tables)	12 Months Ended
	Dec. 31, 2018
Estimated Future Operating Lease Obligation	Company Estimated Obligation (in millions) AEP $ 1,070.4 AEP Texas 80.2 AEPTCo 5.4 APCo 80.4 I&M 351.1 OPCo 76.8 PSO 32.2 SWEPCo 35.8

Comprehensive Income (Tables)

Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 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, 2017 $ (28.4 ) $ (13.0 ) $ 11.9 $ 141.6 $ (179.9 ) $ (67.8 ) Change in Fair Value Recognized in AOCI 37.3 2.3 — — (33.0 ) 6.6 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — — — (0.1 ) Purchased Electricity for Resale (a) (32.6 ) — — — — (32.6 ) Interest Expense (a) — 1.1 — — — 1.1 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains) Losses — — — 12.8 — 12.8 Reclassifications from AOCI, before Income Tax (Expense) Benefit (32.7 ) 1.1 — (6.7 ) — (38.3 ) Income Tax (Expense) Benefit (6.9 ) 0.3 — (1.4 ) — (8.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (25.8 ) 0.8 — (5.3 ) — (30.3 ) Net Current Period Other Comprehensive Income (Loss) 11.5 3.1 — (5.3 ) (33.0 ) (23.7 ) ASU 2018-02 Adoption (b) (6.1 ) (2.7 ) — — (8.2 ) (17.0 ) ASU 2016-01 Adoption (b) — — (11.9 ) — — (11.9 ) Balance in AOCI as of December 31, 2018 $ (23.0 ) $ (12.6 ) $ — $ 136.3 $ (221.1 ) $ (120.4 ) 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 (a) (5.6 ) — — — — (5.6 ) Purchased Electricity for Resale (a) 28.8 — — — — 28.8 Interest Expense (a) — 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) Benefit 23.2 1.5 — 1.7 — 26.4 Income Tax (Expense) Benefit 8.1 0.4 — 0.6 — 9.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 (a) (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale (a) 16.4 — — — — 16.4 Interest Expense (a) — 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) Benefit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Benefit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2017 $ (4.5 ) $ 4.5 $ (12.6 ) $ (12.6 ) Change in Fair Value Recognized in AOCI — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains) Losses — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.3 0.3 — 1.6 Income Tax (Expense) Benefit 0.3 0.1 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.0 0.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.0 0.2 (1.0 ) 0.2 ASU 2018-02 Adoption (b) (0.9 ) — (1.8 ) (2.7 ) Balance in AOCI as of December 31, 2018 $ (4.4 ) $ 4.7 $ (15.4 ) $ (15.1 ) 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 (a) 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1 ) — (0.1 ) Amortization of Actuarial (Gains) Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.3 0.4 — 1.7 Income Tax (Expense) Benefit 0.4 0.1 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.9 0.3 — 1.2 Net Current Period Other Comprehensive Income (Loss) 0.9 0.3 1.1 2.3 Balance in AOCI as of December 31, 2017 $ (4.5 ) $ 4.5 $ (12.6 ) $ (12.6 ) 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 (a) 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) Benefit 1.8 0.4 — 2.2 Income Tax (Expense) Benefit 0.6 0.1 — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2017 $ — $ 2.2 $ 14.8 $ (15.7 ) $ 1.3 Change in Fair Value Recognized in AOCI (0.7 ) — — (2.6 ) (3.3 ) Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (a) 0.9 — — — 0.9 Interest Expense (a) — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.2 ) — (5.2 ) Amortization of Actuarial (Gains) Losses — — 1.3 — 1.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.9 (1.1 ) (3.9 ) — (4.1 ) Income Tax (Expense) Benefit 0.2 (0.2 ) (0.8 ) — (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.7 (0.9 ) (3.1 ) — (3.3 ) Net Current Period Other Comprehensive Income (Loss) — (0.9 ) (3.1 ) (2.6 ) (6.6 ) ASU 2018-02 Adoption (b) — 0.5 — (0.2 ) 0.3 Balance in AOCI as of December 31, 2018 $ — $ 1.8 $ 11.7 $ (18.5 ) $ (5.0 ) 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 (a) (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) Benefit (1.1 ) (1.8 ) — (2.9 ) Income Tax (Expense) Benefit (0.4 ) (0.6 ) — (1.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 (a) (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) Benefit (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Benefit (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2017 $ (10.7 ) $ 5.1 $ (6.5 ) $ (12.1 ) Change in Fair Value Recognized in AOCI — — (0.6 ) (0.6 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 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) Benefit 2.0 — — 2.0 Income Tax (Expense) Benefit 0.4 — — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 — — 1.6 Net Current Period Other Comprehensive Income (Loss) 1.6 — (0.6 ) 1.0 ASU 2018-02 Adoption (b) (2.4 ) — (0.3 ) (2.7 ) Balance in AOCI as of December 31, 2018 $ (11.5 ) $ 5.1 $ (7.4 ) $ (13.8 ) 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 (a) 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) Benefit 2.0 — — 2.0 Income Tax (Expense) Benefit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 (a) 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) Benefit 2.0 — — 2.0 Income Tax (Expense) Benefit 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 1.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.7 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.7 ) Income Tax (Expense) Benefit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) ASU 2018-02 Adoption (b) 0.4 Balance in AOCI as of December 31, 2018 $ 1.0 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 (a) (1.7 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.7 ) Income Tax (Expense) Benefit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 (a) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.9 ) Income Tax (Expense) Benefit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.3 ) Net Current Period Other Comprehensive Income (Loss) (1.3 ) Balance in AOCI as of December 31, 2016 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 2.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3 ) Income Tax (Expense) Benefit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0 ) Net Current Period Other Comprehensive Income (Loss) (1.0 ) ASU 2018-02 Adoption (b) 0.5 Balance in AOCI as of December 31, 2018 $ 2.1 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 (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3 ) Income Tax (Expense) Benefit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (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 (a) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.2 ) Income Tax (Expense) Benefit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of December 31, 2016 $ 3.4 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2018 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 1.2 $ 0.8 $ (4.0 ) Change in Fair Value Recognized in AOCI 2.3 — (3.1 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 2.1 — — 2.1 Amortization of Prior Service Cost (Credit) — (2.0 ) — (2.0 ) Amortization of Actuarial (Gains) Losses — 0.2 — 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.1 (1.8 ) — 0.3 Income Tax (Expense) Benefit 0.4 (0.4 ) — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.7 (1.4 ) — 0.3 Net Current Period Other Comprehensive Income (Loss) 4.0 (1.4 ) (3.1 ) (0.5 ) ASU 2018-02 Adoption (b) (1.3 ) — 0.4 (0.9 ) Balance in AOCI as of December 31, 2018 $ (3.3 ) $ (0.2 ) $ (1.9 ) $ (5.4 ) 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 (a) 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) Benefit 2.2 (1.1 ) — 1.1 Income Tax (Expense) Benefit 0.8 (0.4 ) — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 (a) 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) Benefit 2.7 (1.1 ) — 1.6 Income Tax (Expense) Benefit 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 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 ) (a) Amounts reclassified to the referenced line item on the statements of income. (b) See Note 2 - New Accounting Pronouncements for additional information.

Rate Matters Rate Matters (Tabl

Rate Matters Rate Matters (Tables)	12 Months Ended
	Dec. 31, 2018
Total Hurricane Harvey Storm Costs	December 31, 2018 Total Hurricane Harvey Storm Costs Capital O&M Regulatory Asset Total (in millions) Restoration Costs Incurred $ 219.1 $ 136.9 $ — $ 356.0 Incremental Operation and Maintenance Expenses (O&M) — (129.8 ) 129.8 — Insurance Proceeds (12.7 ) — (1.2 ) (13.9 ) Total Hurricane Harvey Storm Costs, Net $ 206.4 $ 7.1 $ 128.6 $ 342.1
Total Estimated Storm Costs Requested in the DSRC	Total Estimated Storm Costs Requested in the DSRC December 31, 2018 (in millions) Total Estimated Hurricane Harvey Storm Costs $ 356.0 Estimated Hurricane Harvey Carrying Costs 31.5 Estimated Litigation Costs 0.6 Non-Hurricane Harvey Storm Restoration Costs 36.5 Total Estimated Storm Costs requested in the DSRC 424.6 less: Tax Credit (0.8 ) Insurance Proceeds (8.7 ) Excess ADIT (a) (45.5 ) Total Estimated Storm Costs requested in the DSRC, after adjustments 369.6 less: Settlement Agreement Adjustments (10.6 ) Incremental Insurance Proceeds Received (5.1 ) Total Estimated Storm Costs per Settlement Agreement $ 353.9 (a) Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements.

Effects of Regulation (Tables)

Effects of Regulation (Tables)	12 Months Ended
	Dec. 31, 2018
Regulated Generating Unit to be Retired by 2020	Gross Investment Accumulated Depreciation Net Investment Accelerated Depreciation Regulatory Asset (a) Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (dollars in millions) $ 106.6 $ 62.8 $ 43.8 $ 5.5 $ 3.1 $ 5.0 2020 28 years (a) In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station. See “2018 Oklahoma Base Rate Case” section of Note 4 for additional information.
Regulatory Assets	APCo December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Current Regulatory Assets Under-recovered Fuel Costs, Virginia - earns a return $ 82.4 $ 21.4 1 year Under-recovered Fuel Costs, West Virginia - does not earn a return 17.2 67.4 1 year Total Current Regulatory Assets $ 99.6 $ 88.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.0 $ 9.1 Total Regulatory Assets Currently Earning a Return 9.0 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 35.3 39.7 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Currently Not Earning a Return 35.9 40.3 Total Regulatory Assets Pending Final Regulatory Approval (a) 44.9 49.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.3 86.3 25 years West Virginia Delayed Customer Billing 0.6 7.8 1 year Other Regulatory Assets Approved for Recovery 0.6 3.9 various Total Regulatory Assets Currently Earning a Return 86.5 98.0 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 172.2 168.8 12 years Unamortized Loss on Reacquired Debt 89.3 93.2 27 years Vegetation Management Program - West Virginia 26.6 33.5 3 years Peak Demand Reduction/Energy Efficiency 19.7 18.1 8 years Postemployment Benefits 18.0 18.8 4 years Virginia Generation Rate Adjustment Clause 10.3 7.3 2 years Virginia Transmission Rate Adjustment Clause — 32.6 Storm-Related Costs - West Virginia — 32.2 Other Regulatory Assets Approved for Recovery 8.3 22.0 various Total Regulatory Assets Currently Not Earning a Return 344.4 426.5 Total Regulatory Assets Approved for Recovery 430.9 524.5 Total Noncurrent Regulatory Assets $ 475.8 $ 573.9 (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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. I&M December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 15.0 Total Current Regulatory Assets $ — $ 15.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ — $ 36.3 Cook Plant Turbine — 15.9 Deferred Cook Plant Life Cycle Management Project Costs - Michigan — 14.7 Rockport Plant Dry Sorbent Injection System - Indiana — 10.4 Other Regulatory Assets Pending Final Regulatory Approval 3.3 2.0 Total Regulatory Assets Pending Final Regulatory Approval 3.3 79.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 232.2 245.3 10 years Cook Plant Uprate Project 35.0 — 15 years Deferred Cook Plant Life Cycle Management Project Costs - Michigan 16.1 — 16 years Cook Plant Turbine 15.8 — 20 years Rockport Plant Dry Sorbent Injection System - Indiana 11.5 — 9 years Cook Plant, Unit 2 Baffle Bolts - Indiana 5.7 6.0 20 years Other Regulatory Assets Approved for Recovery 2.4 1.0 various Total Regulatory Assets Currently Earning a Return 318.7 252.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 84.9 77.8 12 years Cook Plant Nuclear Refueling Outage Levelization 37.5 66.7 3 years PJM Costs and Off-system Sales Margin Sharing - Indiana 20.1 57.0 2 years Unamortized Loss on Reacquired Debt 18.7 9.5 30 years Postemployment Benefits 6.5 9.7 4 years Medicare Subsidy 6.1 7.1 6 years Other Regulatory Assets Approved for Recovery 16.7 20.0 various Total Regulatory Assets Currently Not Earning a Return 190.5 247.8 Total Regulatory Assets Approved for Recovery 509.2 500.1 Total Noncurrent Regulatory Assets $ 512.5 $ 579.4 AEP Texas December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) $ 152.4 $ 123.3 Rate Case Expense 0.2 0.1 Total Regulatory Assets Pending Final Regulatory Approval 152.6 123.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Advanced Metering System 45.3 33.5 2 years Meter Replacement Costs 40.1 44.9 9 years Total Regulatory Assets Currently Earning a Return 85.4 78.4 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 176.9 151.2 12 years Unamortized Loss on Reacquired Debt 6.0 7.7 19 years Transmission Cost Recovery Factor 1.7 9.5 2 years Other Regulatory Assets Approved for Recovery 7.4 8.5 various Total Regulatory Assets Currently Not Earning a Return 192.0 176.9 Total Regulatory Assets Approved for Recovery 277.4 255.3 Total Noncurrent Regulatory Assets $ 430.0 $ 378.7 (a) As of December 31, 2018 , AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return (a) $ 0.4 $ 115.9 1 year Total Current Regulatory Assets $ 0.4 $ 115.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 1.0 $ — Total Regulatory Assets Pending Final Regulatory Approval 1.0 — Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Ohio Capacity Deferral 57.8 172.6 1 year Ohio Distribution Decoupling 12.3 61.7 2 years Ohio Basic Transmission Cost Rider — 90.8 Other Regulatory Assets Approved for Recovery 0.9 1.7 various Total Regulatory Assets Currently Earning a Return 71.0 326.8 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 181.5 170.6 12 years Unrealized Loss on Forward Commitments 100.2 131.8 14 years Smart Grid Costs 8.1 — 2 years Postemployment Benefits 7.9 7.2 4 years Unamortized Loss on Reacquired Debt 6.5 7.8 20 years Other Regulatory Assets Approved for Recovery 11.3 8.6 various Total Regulatory Assets Currently Not Earning a Return 315.5 326.0 Total Regulatory Assets Approved for Recovery 386.5 652.8 Total Noncurrent Regulatory Assets $ 387.5 $ 652.8 (a) December 31, 2017 balance includes PIRR. SWEPCo December 31, Remaining Recovery Period 2018 2017 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs, Arkansas/Louisiana - earns a return $ 18.8 $ 14.1 1 year Total Current Regulatory Assets $ 18.8 $ 14.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 50.3 Other Regulatory Assets Pending Final Regulatory Approval 0.3 0.5 Total Regulatory Assets Currently Earning a Return 50.6 50.8 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation - Arkansas, Louisiana 5.3 4.0 Rate Case Expense - Texas 4.9 4.3 Shipe Road Transmission Project - FERC — 3.3 Other Regulatory Assets Pending Final Regulatory Approval 3.6 2.5 Total Regulatory Assets Currently Not Earning a Return 13.8 14.1 Total Regulatory Assets Pending Final Regulatory Approval 64.4 64.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Environmental Controls Projects 14.2 — 14 years Other Regulatory Assets Approved for Recovery 7.2 7.2 various Total Regulatory Assets Currently Earning a Return 21.4 7.2 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 108.4 101.0 12 years Plant Retirement Costs - Unrecovered Plant 17.1 17.6 23 years Unamortized Loss on Reacquired Debt 7.4 4.7 25 years Medicare Subsidy 3.2 3.7 6 years Environmental Controls Projects — 15.3 Other Regulatory Assets Approved for Recovery 8.9 6.2 various Total Regulatory Assets Currently Not Earning a Return 145.0 148.5 Total Regulatory Assets Approved for Recovery 166.4 155.7 Total Noncurrent Regulatory Assets $ 230.8 $ 220.6 AEP December 31, Remaining Recovery Period 2018 2017 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 101.7 $ 203.1 1 year Under-recovered Fuel Costs - does not earn a return 48.4 89.4 1 year Total Current Regulatory Assets $ 150.1 $ 292.5 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 50.3 $ 50.3 Kentucky Deferred Purchased Power Expenses 14.5 — Other Regulatory Assets Pending Final Regulatory Approval 14.8 9.6 Total Regulatory Assets Currently Earning a Return 79.6 59.9 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 152.4 128.0 Plant Retirement Costs - Asset Retirement Obligation Costs 35.3 39.7 Cook Plant Uprate Project — 36.3 Cook Plant Turbine — 15.9 Other Regulatory Assets Pending Final Regulatory Approval 20.7 42.2 Total Regulatory Assets Currently Not Earning a Return 208.4 262.1 Total Regulatory Assets Pending Final Regulatory Approval (b) 288.0 322.0 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 680.9 682.6 25 years Meter Replacement Costs 74.4 83.7 9 years Plant Retirement Costs - Asset Retirement Obligation Costs 64.3 34.3 22 years Ohio Capacity Deferral 57.8 172.6 1 year Advanced Metering System 45.3 33.5 2 years Environmental Control Projects 43.4 28.1 22 years Cook Plant Uprate Project 35.0 — 15 years Storm-Related Costs 31.1 39.3 4 years Mitchell Plant Transfer - West Virginia 17.0 17.8 22 years Deferred Cook Plant Life Cycle Management Project Costs - Michigan 16.1 — 16 years Cook Plant Turbine 15.8 — 20 years Ohio Distribution Decoupling 12.3 61.7 2 years Ohio Basic Transmission Cost Rider — 90.8 Other Regulatory Assets Approved for Recovery 46.1 49.4 various Total Regulatory Assets Currently Earning a Return 1,139.5 1,293.8 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,326.6 1,196.3 12 years Unamortized Loss on Reacquired Debt 134.2 129.9 30 years Unrealized Loss on Forward Commitments 104.6 139.3 14 years Cook Plant Nuclear Refueling Outage Levelization 37.5 66.7 3 years Postemployment Benefits 35.6 39.1 4 years Peak Demand Reduction/Energy Efficiency 31.9 40.1 8 years Medicare Subsidy 27.9 32.5 6 years Vegetation Management - West Virginia 26.6 33.5 3 years PJM/SPP Annual Formula Rate True Up 22.0 11.7 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 21.6 37.2 22 years PJM Costs and Off-system Sales Margin Sharing - Indiana 20.1 57.0 2 years Storm-Related Costs 11.3 44.2 5 years Virginia Transmission Rate Adjustment Clause — 32.6 Other Regulatory Assets Approved for Recovery 83.0 111.7 various Total Regulatory Assets Currently Not Earning a Return 1,882.9 1,971.8 Total Regulatory Assets Approved for Recovery 3,022.4 3,265.6 Total Noncurrent Regulatory Assets $ 3,310.4 $ 3,587.6 (a) As of December 31, 2018 , AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information. (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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. AEPTCo December 31, Remaining Recovery Period Regulatory Assets: 2018 2017 (in millions) Noncurrent Regulatory Assets Regulatory assets approved for recovery: Regulatory Assets Currently Not Earning a Return PJM/SPP Annual Formula Rate True Up $ 12.9 $ 11.7 2 years Total Regulatory Assets Approved for Recovery 12.9 11.7 Total Noncurrent Regulatory Assets $ 12.9 $ 11.7 PSO December 31, Remaining Recovery Period 2018 2017 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 36.7 Total Current Regulatory Assets $ — $ 36.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Oklaunion Power Station Accelerated Depreciation $ 5.5 $ — Total Regulatory Assets Currently Earning a Return 5.5 — Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval 0.5 3.3 Total Regulatory Assets Currently Not Earning a Return 0.5 3.3 Total Regulatory Assets Pending Final Regulatory Approval 6.0 3.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 153.4 138.5 22 years Meter Replacement Costs 34.3 38.8 9 years Storm-Related Costs 31.1 39.0 4 years Environmental Control Projects 29.2 28.1 22 years Red Rock Generating Facility 8.6 8.8 38 years Other Regulatory Assets Approved for Recovery 0.5 0.5 various Total Regulatory Assets Currently Earning a Return 257.1 253.7 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 84.3 72.7 12 years Peak Demand Reduction/Energy Efficiency 6.3 13.0 2 years Unamortized Loss on Reacquired Debt 4.3 5.0 14 years SPP Base Plan Fees 1.4 16.3 2 years Other Regulatory Assets Approved for Recovery 9.6 4.1 various Total Regulatory Assets Currently Not Earning a Return 105.9 111.1 Total Regulatory Assets Approved for Recovery 363.0 364.8 Total Noncurrent Regulatory Assets $ 369.0 $ 368.1
Regulatory Liabilities	SWEPCo December 31, Remaining Refund Period 2018 2017 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs, Texas - pays a return $ 11.1 $ 8.7 1 year Total Current Regulatory Liabilities $ 11.1 $ 8.7 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 280.1 $ 650.5 Excess ADIT that is Not Subject to Rate Normalization Requirements 26.9 62.7 Total Regulatory Liabilities Pending Final Regulatory Determination 307.0 713.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 437.8 424.5 (b) Other Regulatory Liabilities Approved for Payment 2.5 2.6 various Total Regulatory Liabilities Currently Paying a Return 440.3 427.1 Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 4.5 5.9 13 years Other Regulatory Liabilities Approved for Payment 4.9 7.5 various Total Regulatory Liabilities Currently Not Paying a Return 9.4 13.4 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 370.5 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 54.3 — 2 years Income Taxes Subject to Flow Through (258.5 ) (257.3 ) 31 years Total Income Tax Related Regulatory Liabilities 166.3 (257.3 ) Total Regulatory Liabilities Approved for Payment 616.0 183.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 923.0 $ 896.4 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. OPCo December 31, Remaining Refund Period 2018 2017 Regulatory Liabilities: (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ 0.2 $ 0.2 Total Regulatory Liabilities Currently Not Paying a Return 0.2 0.2 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property — 436.3 Excess ADIT that is Not Subject to Rate Normalization Requirements — 230.8 Total Income Tax Related Regulatory Liabilities — 667.1 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 667.3 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 436.6 428.8 (b) Ohio Basic Transmission Cost Rider 68.8 — 2 years Other Regulatory Liabilities Approved for Payment 0.4 1.4 various Total Regulatory Liabilities Currently Paying a Return 505.8 430.2 Regulatory Liabilities Currently Not Paying a Return PJM Transmission Enhancement Refund 71.3 — 7 years Ohio Enhanced Service Reliability Plan 43.1 30.6 2 years Peak Demand Reduction/Energy Efficiency 14.9 23.6 2 years Distribution Investment Rider 7.8 0.3 2 years Other Regulatory Liabilities Approved for Payment 11.3 11.1 various Total Regulatory Liabilities Currently Not Paying a Return 148.4 65.6 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 350.5 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 279.1 — 10 years Income Taxes Subject to Flow Through (62.8 ) (62.9 ) 29 years Total Income Tax Related Regulatory Liabilities 566.8 (62.9 ) Total Regulatory Liabilities Approved for Payment 1,221.0 432.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,221.2 $ 1,100.2 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 268.2 $ 794.4 Excess ADIT that is Not Subject to Rate Normalization Requirements 283.7 381.1 Total Regulatory Liabilities Pending Final Regulatory Determination 551.9 1,175.5 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 618.3 615.8 (b) Deferred Investment Tax Credits 1.0 0.9 42 years Total Regulatory Liabilities Currently Paying a Return 619.3 616.7 Regulatory Liabilities Currently Not Paying a Return PJM Transmission Enhancement Refund 47.7 — 7 years Unrealized Gain on Forward Commitments 34.7 9.5 6 years Virginia Transmission Rate Adjustment Clause 11.3 — 2 years Consumer Rate Relief - West Virginia 8.8 6.5 1 year Other Regulatory Liabilities Approved for Payment 3.9 1.9 various Total Regulatory Liabilities Currently Not Paying a Return 106.4 17.9 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 453.5 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 84.5 — 10 years Income Taxes Subject to Flow Through (365.9 ) (355.2 ) 26 years Total Income Tax Related Regulatory Liabilities 172.1 (355.2 ) Total Regulatory Liabilities Approved for Payment 897.8 279.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,449.7 $ 1,454.9 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs, Michigan - pays a return $ 4.5 $ — 1 year Over-recovered Fuel Costs, Indiana - does not pay a return 22.9 2.7 1 year Total Current Regulatory Liabilities $ 27.4 $ 2.7 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 125.0 $ 534.6 Excess ADIT that is Not Subject to Rate Normalization Requirements 40.6 193.0 Total Regulatory Liabilities Pending Final Regulatory Determination 165.6 727.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 182.5 202.2 (b) Total Regulatory Liabilities Currently Paying a Return 182.5 202.2 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 828.5 945.0 (c) Spent Nuclear Fuel 42.9 43.2 (c) Deferred Investment Tax Credits 29.4 34.1 21 years PJM Transmission Enhancement Refund 29.1 — 7 years Other Regulatory Liabilities Approved for Payment 24.0 11.5 various Total Regulatory Liabilities Currently Not Paying a Return 953.9 1,033.8 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 362.0 — (d) Excess ADIT that is Not Subject to Rate Normalization Requirements 192.6 — 10 years Income Taxes Subject to Flow Through (282.1 ) (254.9 ) 26 years Total Income Tax Related Regulatory Liabilities 272.5 (254.9 ) Total Regulatory Liabilities Approved for Payment 1,408.9 981.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,574.5 $ 1,708.7 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. (d) Refunded using ARAM. PSO December 31, Remaining Refund Period 2018 2017 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 20.1 $ — 1 year Total Current Regulatory Liabilities $ 20.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ — $ 447.7 Excess ADIT that is Not Subject to Rate Normalization Requirements — 92.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 539.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 276.8 268.8 (b) Total Regulatory Liabilities Currently Paying a Return 276.8 268.8 Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 51.5 50.7 26 years Other Regulatory Liabilities Approved for Payment 2.5 2.3 various Total Regulatory Liabilities Currently Not Paying a Return 54.0 53.0 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 415.2 — (c) Excess ADIT that is Not Subject to Rate Normalization Requirements 126.4 — 10 years Income Taxes Subject to Flow Through (7.7 ) (8.1 ) 27 years Total Income Tax Related Regulatory Liabilities 533.9 (8.1 ) Total Regulatory Liabilities Approved for Payment 864.7 313.7 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 864.7 $ 853.5 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. AEPTCo December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Noncurrent Regulatory Liabilities Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 73.9 $ 512.8 Excess ADIT that is Not Subject to Rate Normalization Requirements 4.5 (20.6 ) Total Regulatory Liabilities Pending Final Regulatory Determination 78.4 492.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 99.5 66.7 (c) Total Regulatory Liabilities Currently Paying a Return 99.5 66.7 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 453.4 — (d) Excess ADIT that is Not Subject to Rate Normalization Requirements (28.5 ) — 10 years Income Taxes Subject to Flow Through (b) (81.5 ) (65.1 ) 52 years Total Income Tax Related Regulatory Liabilities 343.4 (65.1 ) Total Regulatory Liabilities Approved for Payment 442.9 1.6 Total Noncurrent Regulatory Liabilities $ 521.3 $ 493.8 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) The 2017 balance reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters. (c) Relieved as removal costs are incurred. (d) Refunded using ARAM. AEP Texas December 31, Remaining Refund Period Regulatory Liabilities: 2018 2017 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property $ 277.1 $ 578.3 Excess ADIT that is Not Subject to Rate Normalization Requirements 141.4 103.3 Total Regulatory Liabilities Pending Final Regulatory Determination 418.5 681.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 645.2 599.2 (b) Advanced Metering Infrastructure Surcharge 8.5 12.7 2 years Excess Earnings 6.3 6.8 13 years Total Regulatory Liabilities Currently Paying a Return 660.0 618.7 Regulatory Liabilities Currently Not Paying a Return Transition Charges - Texas 46.0 46.0 6 years Deferred Investment Tax Credits 10.8 12.3 44 years Other Regulatory Liabilities Approved for Payment — 0.6 various Total Regulatory Liabilities Currently Not Paying a Return 56.8 58.9 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 251.8 — (c) Income Taxes Subject to Flow Through (42.8 ) (38.7 ) 31 years Total Income Tax Related Regulatory Liabilities 209.0 (38.7 ) Total Regulatory Liabilities Approved for Payment 925.8 638.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,344.3 $ 1,320.5 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Refunded using ARAM. AEP December 31, Remaining 2018 2017 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 35.7 $ 8.7 1 year Over-recovered Fuel Costs - does not pay a return 22.9 3.2 1 year Total Current Regulatory Liabilities $ 58.6 $ 11.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ 0.2 $ 0.2 Total Regulatory Liabilities Currently Not Paying a Return 0.2 0.2 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 1,025.3 4,256.7 Excess ADIT that is Not Subject to Rate Normalization Requirements 695.0 1,378.0 Total Income Tax Related Regulatory Liabilities 1,720.3 5,634.7 Total Regulatory Liabilities Pending Final Regulatory Determination 1,720.5 5,634.9 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,742.8 2,637.1 (b) Ohio Basic Transmission Cost Rider 68.8 — 2 years Excess Earnings 8.9 9.4 35 years Deferred Investment Tax Credits 8.7 10.6 42 years Advanced Metering Infrastructure Surcharge 8.5 12.7 2 years Other Regulatory Liabilities Approved for Payment 0.4 1.3 various Total Regulatory Liabilities Currently Paying a Return 2,838.1 2,671.1 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 828.5 945.0 (c) Deferred Investment Tax Credits 204.9 191.2 44 years PJM Transmission Enhancement Refund 164.2 — 7 years Transition Charges - Texas 46.0 46.0 6 years Unrealized Gain on Forward Commitments 45.9 15.0 6 years Ohio Enhanced Service Reliability Plan 43.1 30.6 2 years Spent Nuclear Fuel 42.9 43.2 (c) Peak Demand Reduction/Energy Efficiency 17.5 25.6 3 years Other Regulatory Liabilities Approved for Payment 84.8 41.6 various Total Regulatory Liabilities Currently Not Paying a Return 1,477.8 1,338.2 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 2,925.7 — (d) Excess ADIT that is Not Subject to Rate Normalization Requirements 864.3 — 18 years Income Taxes Subject to Flow Through (1,286.1 ) (1,221.9 ) 56 years Total Income Tax Related Regulatory Liabilities 2,503.9 (1,221.9 ) Total Regulatory Liabilities Approved for Payment 6,819.8 2,787.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,540.3 $ 8,422.3 (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. See “Federal Tax Reform” section of Note 12 for additional information. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. (d) Refunded using ARAM.

Commitments, Guarantees and C_2

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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) $ 1,081.7 $ 1,020.7 $ 306.7 $ 135.0 $ 2,544.1 Energy and Capacity Purchase Contracts 239.7 463.6 324.3 1,337.2 2,364.8 Total $ 1,321.4 $ 1,484.3 $ 631.0 $ 1,472.2 $ 4,908.9 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 391.8 $ 390.1 $ 8.4 $ 0.5 $ 790.8 Energy and Capacity Purchase Contracts 37.0 72.0 74.0 317.7 500.7 Total $ 428.8 $ 462.1 $ 82.4 $ 318.2 $ 1,291.5 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 251.4 $ 293.1 $ 187.8 $ 83.8 $ 816.1 Energy and Capacity Purchase Contracts 126.8 264.0 166.4 322.3 879.5 Total $ 378.2 $ 557.1 $ 354.2 $ 406.1 $ 1,695.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 31.0 $ 59.2 $ 60.2 $ 338.6 $ 489.0 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 58.4 $ 69.7 $ 20.1 $ — $ 148.2 Energy and Capacity Purchase Contracts 93.0 182.2 75.3 226.2 576.7 Total $ 151.4 $ 251.9 $ 95.4 $ 226.2 $ 724.9 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 108.8 $ 132.1 $ 32.6 $ — $ 273.5 Energy and Capacity Purchase Contracts 33.4 62.4 50.2 125.8 271.8 Total $ 142.2 $ 194.5 $ 82.8 $ 125.8 $ 545.3 (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 Issued Under the Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 60.6 January 2019 to December 2019 AEP Texas (a) 2.8 January 2019 OPCo 0.6 September 2019 (a) In January 2019, the letter of credit was amended to $2.2 million and the maturity date was extended until January 2020.

Dispositions, Assets and Liab_2

Dispositions, Assets and Liabilities Held for Sale and Impairments (Tables)	12 Months Ended
	Dec. 31, 2018
Dispositions, Assets and Liabilities Held for Sale	Year Ended December 31, 2016 (in millions) Revenue $ 18.2 Other Operation Expense 6.5 Maintenance Expense 3.4 Asset Impairment and Other Related Charges 72.7 Depreciation and Amortization Expense 9.8 Taxes Other Than Income Taxes 1.3 Total Expenses 93.7 Other Income (Expense) (0.8 ) Pretax Loss of Discontinued Operations (76.3 ) Income Tax Benefit (27.5 ) Total Loss on Discontinued Operations as Presented on the Statements of Income $ (48.8 )
Impaired Assets	Impaired Assets Book Value Fair Value Impairment (in millions) Merchant Coal-Fired Generation Assets $ 2,139.4 $ — $ 2,139.4 Desert Sky and Trent 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, 2018
Health Care Trend Rates	December 31, Health Care Trend Rates 2018 2017 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2024
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	PSO Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 276.6 $ 266.7 $ 69.4 $ 77.6 Service Cost 7.0 6.4 0.7 0.7 Interest Cost 9.9 10.7 2.5 3.2 Actuarial (Gain) Loss (18.9 ) 10.1 (5.6 ) (7.5 ) Benefit Payments (20.8 ) (17.3 ) (6.7 ) (6.9 ) Participant Contributions — — 2.0 2.3 Benefit Obligation as of December 31, $ 253.8 $ 276.6 $ 62.3 $ 69.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 287.8 $ 266.0 $ 95.5 $ 86.4 Actual Gain (Loss) on Plan Assets (5.9 ) 33.6 (9.2 ) 13.7 Company Contributions 0.1 5.5 2.7 — Participant Contributions — — 2.0 2.3 Benefit Payments (20.8 ) (17.3 ) (6.7 ) (6.9 ) Fair Value of Plan Assets as of December 31, $ 261.2 $ 287.8 $ 84.3 $ 95.5 Funded Status as of December 31, $ 7.4 $ 11.2 $ 22.0 $ 26.1 AEP Texas Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 441.3 $ 421.7 $ 107.1 $ 120.4 Service Cost 9.2 8.6 0.9 0.9 Interest Cost 16.0 17.1 3.8 4.9 Actuarial (Gain) Loss (20.9 ) 25.6 (8.3 ) (11.9 ) Benefit Payments (36.3 ) (31.7 ) (10.7 ) (10.8 ) Participant Contributions — — 3.1 3.6 Benefit Obligation as of December 31, $ 409.3 $ 441.3 $ 95.9 $ 107.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 455.9 $ 416.6 $ 147.3 $ 134.1 Actual Gain (Loss) on Plan Assets (9.3 ) 61.8 (14.6 ) 20.4 Company Contributions 0.4 9.2 4.8 — Participant Contributions — — 3.1 3.6 Benefit Payments (36.3 ) (31.7 ) (10.7 ) (10.8 ) Fair Value of Plan Assets as of December 31, $ 410.7 $ 455.9 $ 129.9 $ 147.3 Funded Status as of December 31, $ 1.4 $ 14.6 $ 34.0 $ 40.2 I&M Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 624.3 $ 611.6 $ 153.5 $ 167.6 Service Cost 13.6 14.0 1.6 1.6 Interest Cost 22.1 24.3 5.4 6.9 Actuarial (Gain) Loss (53.9 ) 10.8 (10.6 ) (12.0 ) Benefit Payments (39.1 ) (36.4 ) (16.2 ) (15.6 ) Participant Contributions — — 4.5 4.9 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 567.0 $ 624.3 $ 138.3 $ 153.5 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 636.7 $ 586.1 $ 211.1 $ 186.6 Actual Gain (Loss) on Plan Assets (13.8 ) 74.0 (12.1 ) 35.2 Company Contributions — 13.0 — — Participant Contributions — — 4.5 4.9 Benefit Payments (39.1 ) (36.4 ) (16.2 ) (15.6 ) Fair Value of Plan Assets as of December 31, $ 583.8 $ 636.7 $ 187.3 $ 211.1 Funded Status as of December 31, $ 16.8 $ 12.4 $ 49.0 $ 57.6 AEP Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,215.8 $ 5,085.8 $ 1,332.0 $ 1,447.4 Service Cost 97.6 96.5 11.6 11.2 Interest Cost 187.8 203.1 47.4 59.3 Actuarial (Gain) Loss (306.3 ) 182.4 (100.1 ) (97.5 ) Benefit Payments (384.6 ) (352.0 ) (133.6 ) (128.6 ) Participant Contributions — — 36.5 39.5 Medicare Subsidy — — 0.7 0.7 Benefit Obligation as of December 31, $ 4,810.3 $ 5,215.8 $ 1,194.5 $ 1,332.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 5,174.1 $ 4,827.3 $ 1,732.5 $ 1,545.9 Actual Gain (Loss) on Plan Assets (104.9 ) 600.0 (118.3 ) 271.6 Company Contributions (a) 11.3 98.8 17.1 4.1 Participant Contributions — — 36.5 39.5 Benefit Payments (384.6 ) (352.0 ) (133.6 ) (128.6 ) Fair Value of Plan Assets as of December 31, $ 4,695.9 $ 5,174.1 $ 1,534.2 $ 1,732.5 Funded (Underfunded) Status as of December 31, $ (114.4 ) $ (41.7 ) $ 339.7 $ 400.5 (a) Contributions to the qualified pension plan were $0 and $93 million for the years ended December 31, 2018 and 2017 , respectively. Contributions to the nonqualified pension plans were $11 million and $6 million for the years ended December 31, 2018 and 2017 , respectively. SWEPCo Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 314.6 $ 296.6 $ 80.3 $ 86.9 Service Cost 9.3 8.7 0.9 0.9 Interest Cost 11.3 12.3 2.8 3.6 Actuarial (Gain) Loss (19.2 ) 16.3 (5.9 ) (6.2 ) Benefit Payments (24.6 ) (19.3 ) (7.7 ) (7.4 ) Participant Contributions — — 2.3 2.5 Benefit Obligation as of December 31, $ 291.4 $ 314.6 $ 72.7 $ 80.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 311.7 $ 287.3 $ 110.4 $ 96.8 Actual Gain (Loss) on Plan Assets (7.3 ) 34.6 (9.2 ) 18.5 Company Contributions 1.2 9.1 2.7 — Participant Contributions — — 2.3 2.5 Benefit Payments (24.6 ) (19.3 ) (7.7 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 281.0 $ 311.7 $ 98.5 $ 110.4 Funded (Underfunded) Status as of December 31, $ (10.4 ) $ (2.9 ) $ 25.8 $ 30.1 OPCo Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 501.1 $ 492.9 $ 144.3 $ 164.0 Service Cost 7.7 7.5 0.9 0.9 Interest Cost 17.7 19.4 5.1 6.7 Actuarial (Gain) Loss (36.6 ) 13.1 (9.4 ) (16.6 ) Benefit Payments (36.0 ) (31.8 ) (15.8 ) (15.5 ) Participant Contributions — — 4.3 4.7 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 453.9 $ 501.1 $ 129.5 $ 144.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 509.1 $ 473.8 $ 198.5 $ 182.6 Actual Gain (Loss) on Plan Assets (7.0 ) 58.9 (11.6 ) 26.7 Company Contributions — 8.2 — — Participant Contributions — — 4.3 4.7 Benefit Payments (36.0 ) (31.8 ) (15.8 ) (15.5 ) Fair Value of Plan Assets as of December 31, $ 466.1 $ 509.1 $ 175.4 $ 198.5 Funded Status as of December 31, $ 12.2 $ 8.0 $ 45.9 $ 54.2 APCo Pension Plans OPEB 2018 2017 2018 2017 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 665.0 $ 654.0 $ 236.5 $ 255.6 Service Cost 9.3 9.4 1.1 1.1 Interest Cost 23.5 25.7 8.2 10.6 Actuarial (Gain) Loss (49.2 ) 15.7 (21.9 ) (13.4 ) Benefit Payments (45.5 ) (39.8 ) (24.7 ) (24.3 ) Participant Contributions — — 6.1 6.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 603.1 $ 665.0 $ 205.5 $ 236.5 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 651.7 $ 606.4 $ 273.4 $ 246.9 Actual Gain (Loss) on Plan Assets (12.9 ) 74.9 (18.7 ) 41.6 Company Contributions — 10.2 2.3 2.5 Participant Contributions — — 6.1 6.7 Benefit Payments (45.5 ) (39.8 ) (24.7 ) (24.3 ) Fair Value of Plan Assets as of December 31, $ 593.3 $ 651.7 $ 238.4 $ 273.4 Funded (Underfunded) Status as of December 31, $ (9.8 ) $ (13.3 ) $ 32.9 $ 36.9
Benefit Amounts Recognized on the Balance Sheets	Pension Plans OPEB December 31, AEP 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ 36.3 $ 392.2 $ 463.0 Other Current Liabilities – Accrued Short-term Benefit Liability (5.7 ) (6.2 ) (2.8 ) (3.2 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (108.7 ) (71.8 ) (49.7 ) (59.3 ) Funded (Underfunded) Status $ (114.4 ) $ (41.7 ) $ 339.7 $ 400.5 Pension Plans OPEB December 31, AEP Texas 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 5.2 $ 18.6 $ 34.0 $ 40.2 Other Current Liabilities – Accrued Short-term Benefit Liability (0.4 ) (0.4 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (3.4 ) (3.6 ) — — Funded Status $ 1.4 $ 14.6 $ 34.0 $ 40.2 Pension Plans OPEB December 31, I&M 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 18.0 $ 13.4 $ 49.0 $ 57.6 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.2 ) (1.0 ) — — Funded Status $ 16.8 $ 12.4 $ 49.0 $ 57.6 Pension Plans OPEB December 31, PSO 2018 2017 2018 2017 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 9.7 $ 13.9 $ 22.0 $ 26.1 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (2.1 ) (2.5 ) — — Funded Status $ 7.4 $ 11.2 $ 22.0 $ 26.1 Pension Plans OPEB December 31, SWEPCo 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.8 $ 30.1 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (10.2 ) (2.7 ) — — Funded (Underfunded) Status $ (10.4 ) $ (2.9 ) $ 25.8 $ 30.1 Pension Plans OPEB December 31, OPCo 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 12.6 $ 8.4 $ 45.9 $ 54.2 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (0.4 ) (0.4 ) — — Funded Status $ 12.2 $ 8.0 $ 45.9 $ 54.2 Pension Plans OPEB December 31, APCo 2018 2017 2018 2017 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 62.3 $ 74.6 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.1 ) (2.5 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.8 ) (13.3 ) (27.3 ) (35.2 ) Funded (Underfunded) Status $ (9.8 ) $ (13.3 ) $ 32.9 $ 36.9
Amounts Included in AOCI and Regulatory Assets	(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. SWEPCo Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 97.4 $ 97.4 $ 33.9 $ 24.7 Prior Service Credit — — (26.2 ) (31.4 ) Recorded as Regulatory Assets $ 97.4 $ 97.4 $ 4.9 $ (3.7 ) Deferred Income Taxes — — 0.7 (0.6 ) Net of Tax AOCI — — 2.1 (2.0 ) Income Tax Expense (a) — — — (0.4 ) AEP Texas Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 182.0 $ 175.2 $ 38.0 $ 23.9 Prior Service Credit — — (29.5 ) (35.4 ) Recorded as Regulatory Assets $ 168.2 $ 161.4 $ 8.7 $ (10.2 ) Deferred Income Taxes 2.9 2.9 — (0.3 ) Net of Tax AOCI 10.9 8.9 (0.2 ) (0.8 ) Income Tax Expense (a) — 2.0 — (0.2 ) PSO Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 77.6 $ 78.8 $ 28.3 $ 19.8 Prior Service Credit — — (21.6 ) (25.9 ) Recorded as Regulatory Assets $ 77.6 $ 78.8 $ 6.7 $ (6.1 ) I&M Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 80.6 $ 94.9 $ 54.7 $ 42.0 Prior Service Credit — — (47.4 ) (56.9 ) Recorded as Regulatory Assets $ 78.4 $ 91.8 $ 6.5 $ (14.0 ) Deferred Income Taxes 0.5 0.7 0.2 (0.2 ) Net of Tax AOCI 1.7 2.0 0.6 (0.6 ) Income Tax Expense (a) — 0.4 — (0.1 ) OPCo Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 180.7 $ 189.6 $ 35.5 $ 22.6 Prior Service Credit — — (34.7 ) (41.6 ) Recorded as Regulatory Assets $ 180.7 $ 189.6 $ 0.8 $ (19.0 ) AEP Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 1,355.2 $ 1,354.2 $ 419.8 $ 309.9 Prior Service Credit — — (347.2 ) (416.3 ) Recorded as Regulatory Assets $ 1,267.9 $ 1,271.3 $ 52.5 $ (82.4 ) Deferred Income Taxes 18.4 17.4 4.2 (5.0 ) Net of Tax AOCI 68.9 53.9 15.9 (15.6 ) Income Tax Expense (a) — 11.6 — (3.4 ) APCo Pension Plans OPEB December 31, 2018 2017 2018 2017 Components (in millions) Net Actuarial Loss $ 172.2 $ 182.5 $ 58.9 $ 48.0 Prior Service Credit — — (50.4 ) (60.4 ) Recorded as Regulatory Assets $ 169.6 $ 179.9 $ 2.6 $ (11.1 ) Deferred Income Taxes 0.5 0.5 1.2 (0.3 ) Net of Tax AOCI 2.1 1.7 4.7 (0.8 ) Income Tax Expense (a) — 0.4 — (0.2 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	APCo Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 0.3 $ (23.3 ) $ 12.8 $ (38.6 ) Amortization of Actuarial Loss (10.6 ) (10.4 ) (1.9 ) (6.3 ) Amortization of Prior Service Credit (Cost) — (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (10.3 ) $ (33.9 ) $ 20.9 $ (34.8 ) PSO Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 3.2 $ (7.9 ) $ 9.0 $ (15.5 ) Amortization of Actuarial Loss (4.4 ) (4.3 ) (0.5 ) (2.0 ) Amortization of Prior Service Credit — — 4.3 4.3 Change for the Year Ended December 31, $ (1.2 ) $ (12.2 ) $ 12.8 $ (13.2 ) SWEPCo Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 5.5 $ (1.5 ) $ 9.8 $ (18.4 ) Amortization of Actuarial Loss (5.5 ) (4.9 ) (0.6 ) (2.3 ) Amortization of Prior Service Credit (Cost) — (0.1 ) 5.2 5.2 Change for the Year Ended December 31, $ — $ (6.5 ) $ 14.4 $ (15.5 ) AEP Texas Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 14.0 $ (11.1 ) $ 14.9 $ (23.6 ) Amortization of Actuarial Loss (7.2 ) (7.0 ) (0.8 ) (3.2 ) Amortization of Prior Service Credit — — 5.9 5.8 Change for the Year Ended December 31, $ 6.8 $ (18.1 ) $ 20.0 $ (21.0 ) I&M Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ (4.5 ) $ (28.6 ) $ 13.9 $ (34.9 ) Amortization of Actuarial Loss (9.8 ) (9.7 ) (1.2 ) (4.4 ) Amortization of Prior Service Credit (Cost) — (0.2 ) 9.5 9.4 Change for the Year Ended December 31, $ (14.3 ) $ (38.5 ) $ 22.2 $ (29.9 ) OPCo Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.9 ) $ (18.0 ) $ 14.0 $ (31.3 ) Amortization of Actuarial Loss (8.0 ) (7.8 ) (1.1 ) (4.3 ) Amortization of Prior Service Credit (Cost) — (0.1 ) 6.9 6.9 Change for the Year Ended December 31, $ (8.9 ) $ (25.9 ) $ 19.8 $ (28.7 ) AEP Pension Plans OPEB 2018 2017 2018 2017 Components (in millions) Actuarial (Gain) Loss During the Year $ 88.8 $ (132.8 ) $ 120.4 $ (267.8 ) Amortization of Actuarial Loss (87.8 ) (82.8 ) (10.5 ) (36.7 ) Amortization of Prior Service Credit (Cost) — (1.0 ) 69.1 69.1 Change for the Year Ended December 31, $ 1.0 $ (216.6 ) $ 179.0 $ (235.4 )
Allocated Assets of Investments	Pension Plan OPEB December 31, Company 2018 2017 2018 2017 AEP Texas 8.7 % 8.8 % 8.5 % 8.5 % APCo 12.6 % 12.6 % 15.5 % 15.8 % I&M 12.4 % 12.3 % 12.2 % 12.2 % OPCo 9.9 % 9.8 % 11.4 % 11.5 % PSO 5.6 % 5.6 % 5.5 % 5.5 % SWEPCo 6.0 % 6.0 % 6.4 % 6.4 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,560.7 $ 393.2 $ 588.3 $ 536.3 $ 438.3 $ 238.0 $ 271.6 Nonqualified Pension Plans 64.9 3.6 0.2 0.6 0.2 2.2 1.2 Total as of December 31, 2018 $ 4,625.6 $ 396.8 $ 588.5 $ 536.9 $ 438.5 $ 240.2 $ 272.8 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
Underfunded Projected Benefit Obligation	AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,810.3 $ 3.8 $ 603.1 $ 1.2 $ 0.4 $ 2.3 $ 291.4 Fair Value of Plan Assets 4,695.9 — 593.3 — — — 281.0 Underfunded Projected Benefit Obligation as of December 31, 2018 $ (114.4 ) $ (3.8 ) $ (9.8 ) $ (1.2 ) $ (0.4 ) $ (2.3 ) $ (10.4 ) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 78.0 $ 4.0 $ 665.0 $ 1.0 $ 0.4 $ 2.7 $ 314.6 Fair Value of Plan Assets — — 651.7 — — — 311.7 Underfunded Projected Benefit Obligation as of December 31, 2017 $ (78.0 ) $ (4.0 ) $ (13.3 ) $ (1.0 ) $ (0.4 ) $ (2.7 ) $ (2.9 )
Underfunded Accumulated Benefit Obligation	AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Accumulated Benefit Obligation $ 64.9 $ 3.6 $ 0.2 $ 0.6 $ 0.2 $ 2.2 $ 1.2 Fair Value of Plan Assets — — — — — — — Underfunded Accumulated Benefit Obligation as of December 31, 2018 $ (64.9 ) $ (3.6 ) $ (0.2 ) $ (0.6 ) $ (0.2 ) $ (2.2 ) $ (1.2 ) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 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 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans OPEB (in millions) AEP $ 98.7 $ 4.5 AEP Texas 8.0 0.1 APCo 7.7 2.1 I&M 1.1 — OPCo 0.5 — PSO 0.2 — SWEPCo 7.9 —
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) 2019 $ 339.8 $ 30.8 $ 43.4 $ 36.2 $ 34.3 $ 19.0 $ 21.4 2020 344.2 34.3 42.8 36.4 34.5 19.5 21.8 2021 354.2 34.9 43.4 37.5 34.0 21.2 22.9 2022 357.3 33.5 43.6 38.9 33.9 20.4 23.8 2023 364.1 34.9 44.2 40.3 34.7 23.1 24.0 Years 2024 to 2028, in Total 1,808.2 164.7 220.2 210.6 163.3 102.5 120.5 OPEB Benefit Payments AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 122.0 $ 10.0 $ 22.0 $ 14.8 $ 14.5 $ 6.3 $ 7.1 2020 126.5 10.5 22.5 15.4 14.8 6.8 7.5 2021 127.1 10.7 22.2 15.7 14.8 6.8 7.8 2022 127.2 10.9 22.1 15.7 14.7 7.0 8.0 2023 126.3 10.9 21.6 15.6 14.5 7.1 8.1 Years 2024 to 2028, in Total 618.8 53.6 103.4 75.6 69.1 34.9 41.5 OPEB Medicare Subsidy Receipts AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 0.2 $ — $ 0.2 $ — $ — $ — $ — 2020 0.2 — 0.2 — — — — 2021 0.3 — 0.2 — — — — 2022 0.3 — 0.2 — — — — 2023 0.3 — 0.2 — — — — Years 2024 to 2028, in Total 1.5 — 0.7 — — — —
Components of Net Periodic Benefit Cost	AEP Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 97.6 $ 96.5 $ 85.8 $ 11.6 $ 11.2 $ 10.2 Interest Cost 187.8 203.1 211.6 47.4 59.3 60.9 Expected Return on Plan Assets (290.3 ) (284.8 ) (280.3 ) (102.2 ) (101.3 ) (107.0 ) Amortization of Prior Service Cost (Credit) — 1.0 2.3 (69.1 ) (69.1 ) (69.0 ) Amortization of Net Actuarial Loss 85.2 82.8 83.8 10.5 36.7 31.4 Settlements 2.6 — — — — — Net Periodic Benefit Cost (Credit) 82.9 98.6 103.2 (101.8 ) (63.2 ) (73.5 ) Capitalized Portion (41.1 ) (39.9 ) (37.8 ) (4.9 ) 25.6 26.9 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 41.8 $ 58.7 $ 65.4 $ (106.7 ) $ (37.6 ) $ (46.6 ) AEP Texas Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 9.2 $ 8.6 $ 7.5 $ 0.9 $ 0.9 $ 0.7 Interest Cost 16.0 17.1 17.8 3.8 4.9 5.1 Expected Return on Plan Assets (25.6 ) (25.0 ) (24.5 ) (8.6 ) (8.8 ) (9.3 ) Amortization of Prior Service Cost (Credit) — — 0.4 (5.9 ) (5.8 ) (6.0 ) Amortization of Net Actuarial Loss 7.2 7.0 7.1 0.8 3.2 2.8 Net Periodic Benefit Cost (Credit) 6.8 7.7 8.3 (9.0 ) (5.6 ) (6.7 ) Capitalized Portion (4.8 ) (4.0 ) (3.6 ) (0.5 ) 2.9 3.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 2.0 $ 3.7 $ 4.7 $ (9.5 ) $ (2.7 ) $ (3.3 ) APCo Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 9.3 $ 9.4 $ 8.1 $ 1.1 $ 1.1 $ 1.0 Interest Cost 23.5 25.7 27.2 8.2 10.6 10.8 Expected Return on Plan Assets (36.6 ) (35.8 ) (35.3 ) (16.0 ) (16.5 ) (17.3 ) Amortization of Prior Service Cost (Credit) — 0.2 0.1 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 10.6 10.4 10.8 1.9 6.3 5.4 Net Periodic Benefit Cost (Credit) 6.8 9.9 10.9 (14.8 ) (8.6 ) (10.2 ) Capitalized Portion (3.8 ) (4.0 ) (4.1 ) (0.5 ) 3.5 3.9 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 3.0 $ 5.9 $ 6.8 $ (15.3 ) $ (5.1 ) $ (6.3 ) I&M Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 13.6 $ 14.0 $ 12.2 $ 1.6 $ 1.6 $ 1.5 Interest Cost 22.1 24.3 25.3 5.4 6.9 7.0 Expected Return on Plan Assets (35.7 ) (34.6 ) (33.6 ) (12.3 ) (12.2 ) (12.9 ) Amortization of Prior Service Cost (Credit) — 0.2 0.1 (9.5 ) (9.4 ) (9.4 ) Amortization of Net Actuarial Loss 9.8 9.7 10.0 1.2 4.4 3.7 Net Periodic Benefit Cost (Credit) 9.8 13.6 14.0 (13.6 ) (8.7 ) (10.1 ) Capitalized Portion (5.6 ) (5.5 ) (3.3 ) (0.7 ) 3.5 2.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 4.2 $ 8.1 $ 10.7 $ (14.3 ) $ (5.2 ) $ (7.7 ) OPCo Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 7.7 $ 7.5 $ 6.5 $ 0.9 $ 0.9 $ 0.8 Interest Cost 17.7 19.4 20.6 5.1 6.7 7.0 Expected Return on Plan Assets (28.8 ) (27.9 ) (27.6 ) (11.7 ) (11.9 ) (13.0 ) Amortization of Prior Service Cost (Credit) — 0.1 0.1 (6.9 ) (6.9 ) (6.9 ) Amortization of Net Actuarial Loss 8.0 7.8 8.1 1.1 4.3 3.8 Net Periodic Benefit Cost (Credit) 4.6 6.9 7.7 (11.5 ) (6.9 ) (8.3 ) Capitalized Portion (3.6 ) (3.3 ) (3.4 ) (0.4 ) 3.3 3.7 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 1.0 $ 3.6 $ 4.3 $ (11.9 ) $ (3.6 ) $ (4.6 ) PSO Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 7.0 $ 6.4 $ 6.2 $ 0.7 $ 0.7 $ 0.6 Interest Cost 9.9 10.7 11.2 2.5 3.2 3.3 Expected Return on Plan Assets (16.1 ) (15.6 ) (15.5 ) (5.6 ) (5.6 ) (6.1 ) Amortization of Prior Service Cost (Credit) — — 0.3 (4.3 ) (4.3 ) (4.3 ) Amortization of Net Actuarial Loss 4.4 4.3 4.4 0.5 2.0 1.8 Net Periodic Benefit Cost (Credit) 5.2 5.8 6.6 (6.2 ) (4.0 ) (4.7 ) Capitalized Portion (2.6 ) (2.1 ) (2.4 ) (0.3 ) 1.4 1.7 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 2.6 $ 3.7 $ 4.2 $ (6.5 ) $ (2.6 ) $ (3.0 ) SWEPCo Pension Plans OPEB Years Ended December 31, 2018 2017 2016 2018 2017 2016 (in millions) Service Cost $ 9.3 $ 8.7 $ 8.1 $ 0.9 $ 0.9 $ 0.8 Interest Cost 11.3 12.3 12.4 2.8 3.6 3.6 Expected Return on Plan Assets (17.3 ) (17.0 ) (16.4 ) (6.4 ) (6.3 ) (6.8 ) Amortization of Prior Service Cost (Credit) — 0.1 0.3 (5.2 ) (5.2 ) (5.0 ) Amortization of Net Actuarial Loss 5.1 4.9 4.8 0.6 2.3 1.9 Settlements 0.4 — — — — — Net Periodic Benefit Cost (Credit) 8.8 9.0 9.2 (7.3 ) (4.7 ) (5.5 ) Capitalized Portion (3.1 ) (2.7 ) (2.7 ) (0.3 ) 1.4 1.6 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 5.7 $ 6.3 $ 6.5 $ (7.6 ) $ (3.3 ) $ (3.9 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2018 2017 2016 (in millions) AEP $ 71.8 $ 74.6 $ 72.9 AEP Texas 5.7 6.0 5.2 APCo 7.5 7.4 7.3 I&M 10.5 10.7 10.9 OPCo 6.3 6.1 5.6 PSO 4.5 5.0 4.3 SWEPCo 5.9 6.0 5.7
Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans OPEB December 31, Assumption 2018 2017 2018 2017 Discount Rate 4.30 % 3.65 % 4.30 % 3.60 % Interest Crediting Rate 4.00 % 4.00 % NA NA NA Not applicable. Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2018 2017 AEP 4.85 % 4.80 % AEP Texas 4.95 % 4.90 % APCo 4.75 % 4.60 % I&M 4.90 % 4.85 % OPCo 5.00 % 4.95 % PSO 4.90 % 4.90 % SWEPCo 4.85 % 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.
Benefit Costs [Member]
Actuarial Assumptions	Pension Plans OPEB Year Ended December 31, Assumption 2018 2017 2016 2018 2017 2016 Discount Rate 3.65 % 4.05 % 4.30 % 3.60 % 4.10 % 4.30 % Interest Crediting Rate 4.00 % 4.00 % 4.00 % NA NA NA Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 6.00 % 6.75 % 7.00 % NA Not applicable. Pension Plans Year Ended December 31, Assumption – Rate of Compensation Increase (a) 2018 2017 2016 AEP 4.85 % 4.80 % 4.75 % AEP Texas 4.95 % 4.90 % 4.85 % APCo 4.75 % 4.60 % 4.55 % I&M 4.90 % 4.85 % 4.80 % OPCo 5.00 % 4.95 % 4.85 % PSO 4.90 % 4.90 % 4.90 % SWEPCo 4.85 % 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.
Pension Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities (a): Domestic $ 318.6 $ — $ — $ — $ 318.6 6.2 % International 507.7 — — — 507.7 9.8 % Options — 26.9 — — 26.9 0.5 % Common Collective Trusts (c) — — — 452.9 452.9 8.7 % Subtotal – Equities 826.3 26.9 — 452.9 1,306.1 25.2 % Fixed Income (a): United States Government and Agency Securities — 1,376.5 — — 1,376.5 26.6 % Corporate Debt — 1,277.0 — — 1,277.0 24.7 % Foreign Debt — 296.9 — — 296.9 5.7 % State and Local Government — 31.7 — — 31.7 0.6 % Other – Asset Backed — 10.2 — — 10.2 0.2 % Subtotal – Fixed Income — 2,992.3 — — 2,992.3 57.8 % Infrastructure (c) — — — 59.5 59.5 1.2 % Real Estate (c) — — — 290.3 290.3 5.6 % Alternative Investments (c) — — — 446.0 446.0 8.6 % Cash and Cash Equivalents (c) 0.4 35.6 — 21.2 57.2 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 22.7 22.7 0.5 % Total $ 826.7 $ 3,054.8 $ — $ 1,292.6 $ 5,174.1 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (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 Allocation (in millions) Equities (a): Domestic $ 277.3 $ — $ — $ — $ 277.3 5.9 % International 384.1 — — — 384.1 8.2 % Options — 18.3 — — 18.3 0.4 % Common Collective Trusts (c) — — — 370.1 370.1 7.9 % Subtotal – Equities 661.4 18.3 — 370.1 1,049.8 22.4 % Fixed Income (a): United States Government and Agency Securities 0.2 1,512.5 — — 1,512.7 32.2 % Corporate Debt — 1,082.9 — — 1,082.9 23.0 % Foreign Debt — 221.6 — — 221.6 4.7 % State and Local Government — 28.2 — — 28.2 0.6 % Other – Asset Backed — 7.4 — — 7.4 0.2 % Subtotal – Fixed Income 0.2 2,852.6 — — 2,852.8 60.7 % Infrastructure (c) — — — 72.2 72.2 1.5 % Real Estate (c) — — — 220.4 220.4 4.7 % Alternative Investments (c) — — — 444.6 444.6 9.5 % Cash and Cash Equivalents (c) (0.4 ) 36.3 — 11.9 47.8 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 8.3 8.3 0.2 % Total $ 661.2 $ 2,907.2 $ — $ 1,127.5 $ 4,695.9 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (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	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 $ 233.3 $ — $ — $ — $ 233.3 15.2 % International 185.9 — — — 185.9 12.1 % Options — 4.3 — — 4.3 0.3 % Common Collective Trusts (b) — — — 226.2 226.2 14.7 % Subtotal – Equities 419.2 4.3 — 226.2 649.7 42.3 % Fixed Income: Common Collective Trust – Debt (b) — — — 163.6 163.6 10.7 % United States Government and Agency Securities 0.2 181.5 — — 181.7 11.8 % Corporate Debt — 188.6 — — 188.6 12.3 % Foreign Debt — 35.0 — — 35.0 2.3 % State and Local Government 41.8 11.8 — — 53.6 3.5 % Other – Asset Backed — 0.2 — — 0.2 — % Subtotal – Fixed Income 42.0 417.1 — 163.6 622.7 40.6 % Trust Owned Life Insurance: International Equities — 49.4 — — 49.4 3.2 % United States Bonds — 154.4 — — 154.4 10.1 % Subtotal – Trust Owned Life Insurance — 203.8 — — 203.8 13.3 % Cash and Cash Equivalents (b) 54.4 — — 4.8 59.2 3.9 % Other – Pending Transactions and Accrued Income (a) — — — (1.2 ) (1.2 ) (0.1 )% Total $ 515.6 $ 625.2 $ — $ 393.4 $ 1,534.2 100.0 % (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 $ 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.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2018
Reportable Segment Information	State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated 2018 (in millions) Revenues from: External Customers $ 177.0 $ — $ — $ 177.0 Sales to AEP Affiliates 598.9 — — 598.9 Other Revenues 0.2 — — 0.2 Total Revenues $ 776.1 $ — $ — $ 776.1 Depreciation and Amortization $ 133.9 $ — $ — $ 133.9 Interest Income 1.3 104.6 (103.4 ) (a) 2.5 Allowance for Equity Funds Used During Construction 70.6 — — 70.6 Interest Expense 83.2 103.4 (103.4 ) (a) 83.2 Income Tax Expense 83.9 0.2 — 84.1 Net Income $ 314.9 $ 1.0 (b) $ — $ 315.9 Gross Property Additions $ 1,570.8 $ — $ — $ 1,570.8 Total Transmission Property $ 8,268.1 $ — $ — $ 8,268.1 Accumulated Depreciation and Amortization 271.9 — — 271.9 Total Transmission Property - Net $ 7,996.2 $ — $ — $ 7,996.2 Notes Receivable - Affiliated $ — $ 2,823.0 $ (2,823.0 ) (c) $ — Total Assets $ 8,406.8 $ 2,857.1 (d) $ (2,869.8 ) (e) $ 8,394.1 Total Long-Term Debt $ 2,850.0 $ 2,823.0 $ (2,850.0 ) (c) $ 2,823.0 State Transcos (f) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (f) 2017 (in millions) Revenues from: External Customers $ 138.0 $ — $ — $ 138.0 Sales to AEP Affiliates 568.1 — — 568.1 Other Revenues 0.8 — — 0.8 Total Revenues $ 706.9 $ — $ — $ 706.9 Depreciation and Amortization $ 95.7 $ — $ — $ 95.7 Interest Income 0.7 82.9 (82.4 ) (a) 1.2 Allowance for Equity Funds Used During Construction 49.0 — — 49.0 Interest Expense 70.2 82.4 (82.4 ) (a) 70.2 Income Tax Expense 142.0 0.2 — 142.2 Net Income $ 270.4 $ 0.3 (b) $ — $ 270.7 Gross Property Additions $ 1,522.5 $ — $ — $ 1,522.5 Total Transmission Property $ 6,770.5 $ — $ — $ 6,770.5 Accumulated Depreciation and Amortization 152.6 — — 152.6 Total Transmission Property - Net $ 6,617.9 $ — $ — $ 6,617.9 Notes Receivable - Affiliated $ — $ 2,550.4 $ (2,550.4 ) (c) $ — Total Assets $ 7,086.9 $ 2,590.1 (d) $ (2,594.9 ) (e) $ 7,082.1 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 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 (Benefit) 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 Assets $ 5,337.5 $ 1,987.7 (d) $ (1,975.4 ) (e) $ 5,349.8 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Includes elimination of AEPTCo Parent’s investments in the State Transcos. (e) Primarily relates to elimination of Notes Receivable from the State Transcos. (f) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2018 Revenues from: External Customers $ 9,556.7 $ 4,552.3 $ 248.6 $ 1,818.1 $ 20.0 $ — $ 16,195.7 Other Operating Segments 88.8 100.8 555.5 122.2 75.1 (942.4 ) — Total Revenues $ 9,645.5 $ 4,653.1 $ 804.1 $ 1,940.3 $ 95.1 $ (942.4 ) $ 16,195.7 Asset Impairments and Other Related Charges $ 3.4 $ — $ — $ 47.7 $ 19.5 $ — $ 70.6 Depreciation and Amortization 1,316.2 734.1 137.8 41.0 0.4 57.1 (b) 2,286.6 Interest and Investment Income 11.7 4.2 2.5 13.1 31.0 (50.9 ) 11.6 Carrying Costs Income (Expense) 5.3 1.7 (0.4 ) — — — 6.6 Interest Expense 567.8 248.1 90.7 14.9 122.6 (59.7 ) (b) 984.4 Income Tax Expense (Benefit) 5.7 42.4 95.3 (49.2 ) 21.1 — 115.3 Net Income (Loss) $ 995.5 $ 527.4 $ 373.0 $ 134.7 $ (99.3 ) $ — $ 1,931.3 Gross Property Additions $ 2,282.2 $ 2,162.4 $ 1,614.1 $ 289.7 $ 16.3 $ (39.2 ) $ 6,325.5 Total Property, Plant and Equipment $ 45,365.1 $ 18,126.7 $ 8,659.5 $ 893.3 $ 395.2 $ (354.6 ) (b) $ 73,085.2 Accumulated Depreciation and Amortization 13,822.5 3,833.7 282.8 47.0 186.6 (186.5 ) (b) 17,986.1 Total Property, Plant and Equipment – Net $ 31,542.6 $ 14,293.0 $ 8,376.7 $ 846.3 $ 208.6 $ (168.1 ) (b) $ 55,099.1 Total Assets $ 38,874.3 $ 17,083.4 $ 9,543.7 $ 1,979.7 $ 4,036.5 (c) $ (2,714.8 ) (b) (d) $ 68,802.8 Investments in Equity Method Investees $ 39.6 $ 2.9 $ 750.9 $ 26.7 $ 26.1 $ — $ 846.2 Long-term Debt Due Within One Year: Nonaffiliated $ 1,066.3 $ 549.1 $ 85.0 $ 0.1 $ (2.0 ) (e) $ — $ 1,698.5 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 11,442.7 5,048.8 2,888.6 (0.3 ) 2,268.4 (e) — 21,648.2 Total Long-term Debt $ 12,559.0 $ 5,597.9 $ 2,973.6 $ 32.0 $ 2,266.4 $ (82.2 ) $ 23,346.7 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 (Expense) 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 425.6 127.2 189.8 189.7 37.4 — 969.7 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: Nonaffiliated $ 1,038.1 $ 663.1 $ 50.0 $ — $ 2.5 $ — $ 1,753.7 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 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 (Expense) 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 (Benefit) 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 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 (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 other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (d) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. (e) Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	12 Months Ended
	Dec. 31, 2018
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2018 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 371.1 — 66.4 40.9 7.8 15.2 4.5 Natural Gas MMBtus 87.9 — 4.0 2.3 — — 15.2 Heating Oil and Gasoline Gallons 7.4 1.5 1.4 0.7 1.8 0.7 0.8 Interest Rate USD $ 37.7 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 500.0 $ — $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ — $ —
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments December 31, 2018 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 $ 397.5 $ 28.5 $ — $ 426.0 $ (263.2 ) $ 162.8 Long-term Risk Management Assets 276.4 16.0 — 292.4 (38.4 ) 254.0 Total Assets 673.9 44.5 — 718.4 (301.6 ) 416.8 Current Risk Management Liabilities 293.8 13.2 2.0 309.0 (254.0 ) 55.0 Long-term Risk Management Liabilities 225.7 56.1 15.4 297.2 (33.8 ) 263.4 Total Liabilities 519.5 69.3 17.4 606.2 (287.8 ) 318.4 Total MTM Derivative Contract Net Assets (Liabilities) $ 154.4 $ (24.8 ) $ (17.4 ) $ 112.2 $ (13.8 ) $ 98.4 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 AEP Texas Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 0.7 (0.5 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.7 (0.5 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.7 ) $ 0.5 $ (0.2 ) 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 APCo Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 114.4 $ (57.2 ) $ 57.2 Long-term Risk Management Assets 3.1 (2.2 ) 0.9 Total Assets 117.5 (59.4 ) 58.1 Current Risk Management Liabilities 56.7 (56.3 ) 0.4 Long-term Risk Management Liabilities 2.4 (2.2 ) 0.2 Total Liabilities 59.1 (58.5 ) 0.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 58.4 $ (0.9 ) $ 57.5 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 I&M Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (41.8 ) $ 8.6 Long-term Risk Management Assets 2.0 (1.4 ) 0.6 Total Assets 52.4 (43.2 ) 9.2 Current Risk Management Liabilities 41.1 (40.8 ) 0.3 Long-term Risk Management Liabilities 1.6 (1.5 ) 0.1 Total Liabilities 42.7 (42.3 ) 0.4 Total MTM Derivative Contract Net Assets (Liabilities) $ 9.7 $ (0.9 ) $ 8.8 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 OPCo Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 6.4 (0.6 ) 5.8 Long-term Risk Management Liabilities 93.8 — 93.8 Total Liabilities 100.2 (0.6 ) 99.6 Total MTM Derivative Contract Net Assets (Liabilities) $ (100.2 ) $ 0.6 $ (99.6 ) 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 ) PSO Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 10.9 $ (0.5 ) $ 10.4 Long-term Risk Management Assets — — — Total Assets 10.9 (0.5 ) 10.4 Current Risk Management Liabilities 1.7 (0.7 ) 1.0 Long-term Risk Management Liabilities — — — Total Liabilities 1.7 (0.7 ) 1.0 Total MTM Derivative Contract Net Assets $ 9.2 $ 0.2 $ 9.4 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 SWEPCo Fair Value of Derivative Instruments December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 5.6 $ (0.8 ) $ 4.8 Long-term Risk Management Assets — — — Total Assets 5.6 (0.8 ) 4.8 Current Risk Management Liabilities 1.5 (1.1 ) 0.4 Long-term Risk Management Liabilities 2.2 — 2.2 Total Liabilities 3.7 (1.1 ) 2.6 Total MTM Derivative Contract Net Assets $ 1.9 $ 0.3 $ 2.2 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 (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) All derivative contracts subject to a master netting arrangement or similar agreement are 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, 2018 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (10.4 ) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.9 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (1.9 ) (8.2 ) — — 0.1 Purchased Electricity for Resale 8.6 — 7.6 0.8 — — — Other Operation 1.7 0.4 0.2 0.2 0.3 0.2 0.2 Maintenance 1.9 0.4 0.4 0.2 0.4 0.2 0.2 Regulatory Assets (a) 27.9 (0.7 ) (0.7 ) 7.1 24.9 (1.1 ) (1.2 ) Regulatory Liabilities (a) 222.7 (0.5 ) 135.5 11.6 — 37.3 11.9 Total Gain (Loss) on Risk Management Contracts $ 291.3 $ (0.4 ) $ 141.1 $ 11.7 $ 25.6 $ 36.6 $ 11.2 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 (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 Fair Value Hedges on Balance Sheet	Carrying Amount of the Hedged Assets/(Liabilities) Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 (in millions) Long-Term Debt (a) $ (478.3 ) $ (489.3 ) $ 17.4 $ 6.1 (a) Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
Gain (Loss) on Hedging Instruments	Twelve Months Ended December 31, 2018 2017 2016 (in millions) Gain (Loss) on Interest Rate Contracts: Gain (Loss) on Fair Value Hedging Instruments (a) $ (11.3 ) $ (4.8 ) $ 1.6 Gain (Loss) on Fair Value Portion of Long-term Debt (a) 11.3 4.8 (1.6 ) (a) Gain (Loss) is included in Interest Expense on the statements of income.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2018 December 31, 2017 Interest Rate Expected to be Expected to be Reclassed to Reclassed to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) AEP Texas $ (4.4 ) $ (1.1 ) $ (4.5 ) $ (0.9 ) APCo 1.8 0.9 2.2 0.7 I&M (11.5 ) (1.6 ) (10.7 ) (1.3 ) OPCo 1.0 1.0 1.9 1.1 PSO 2.1 1.0 2.6 0.8 SWEPCo (3.3 ) (1.5 ) (6.0 ) (1.4 ) Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2018 December 31, 2017 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Gain (Loss) Net of Tax $ (23.0 ) $ (12.6 ) $ (28.4 ) $ (13.0 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 10.4 (1.1 ) 5.5 (0.8 )
Liabilities Subject to Cross Default Provisions	December 31, 2018 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 225.5 $ 1.8 $ 181.0 APCo 0.9 — — I&M 0.5 — — SWEPCo 2.3 — 2.3 December 31, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 243.6 $ 1.3 $ 223.1 APCo 0.6 — 0.5 I&M 0.4 — 0.4 SWEPCo 0.2 — 0.1

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Book Values and Fair Values of Long-term Debt	December 31, 2018 2017 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 23,346.7 $ 24,093.9 $ 21,173.3 $ 23,649.6 AEP Texas 3,881.3 3,964.6 3,649.3 3,964.8 AEPTCo 2,823.0 2,782.4 2,550.4 2,782.9 APCo 4,062.6 4,473.3 3,980.1 4,782.6 I&M 3,035.4 3,070.2 2,745.1 3,014.7 OPCo 1,716.6 1,919.7 1,719.3 2,064.3 PSO 1,287.0 1,361.9 1,286.5 1,457.1 SWEPCo 2,713.4 2,670.2 2,441.9 2,645.9
Other Temporary Investments	December 31, 2018 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 230.6 $ — $ — $ 230.6 Fixed Income Securities – Mutual Funds (b) 106.6 — (2.3 ) 104.3 Equity Securities – Mutual Funds 17.8 16.4 — 34.2 Total Other Temporary Investments $ 355.0 $ 16.4 $ (2.3 ) $ 369.1 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 (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, 2018 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 3.1 14.2 2.3 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — —
Nuclear Trust Fund Investments	December 31, 2018 2017 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 22.5 $ — $ — $ 17.2 $ — $ — Fixed Income Securities: United States Government 996.1 26.7 (7.1 ) 981.2 29.7 (3.6 ) Corporate Debt 52.4 1.1 (1.9 ) 58.7 3.8 (1.2 ) State and Local Government 8.6 0.6 (0.2 ) 8.8 0.8 (0.2 ) Subtotal Fixed Income Securities 1,057.1 28.4 (9.2 ) 1,048.7 34.3 (5.0 ) Equity Securities – Domestic (a) 1,395.3 766.3 — 1,461.7 868.2 (75.5 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,474.9 $ 794.7 $ (9.2 ) $ 2,527.6 $ 902.5 $ (80.5 ) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $784 million and unrealized losses of $18 million . AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2018 2017 2016 (in millions) Proceeds from Investment Sales $ 2,010.0 $ 2,256.3 $ 2,957.7 Purchases of Investments 2,064.7 2,300.5 3,000.0 Gross Realized Gains on Investment Sales 47.5 200.7 46.1 Gross Realized Losses on Investment Sales 32.8 146.0 24.4
Contractual Maturities, Fair Value of Debt Securities	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 359.4 After 1 year through 5 years 358.9 After 5 years through 10 years 176.1 After 10 years 162.7 Total $ 1,057.1
Fair Value, Assets and Liabilities Measured on Recurring Basis	AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 221.5 $ — $ — $ 9.1 $ 230.6 Fixed Income Securities – Mutual Funds 104.3 — — — 104.3 Equity Securities – Mutual Funds (b) 34.2 — — — 34.2 Total Other Temporary Investments 360.0 — — 9.1 369.1 Risk Management Assets Risk Management Commodity Contracts (c) (d) 3.8 326.5 340.9 (288.5 ) 382.7 Cash Flow Hedges: Commodity Hedges (c) — 24.1 12.7 (2.7 ) 34.1 Total Risk Management Assets 3.8 350.6 353.6 (291.2 ) 416.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 12.3 — — 10.2 22.5 Fixed Income Securities: United States Government — 996.1 — — 996.1 Corporate Debt — 52.4 — — 52.4 State and Local Government — 8.6 — — 8.6 Subtotal Fixed Income Securities — 1,057.1 — — 1,057.1 Equity Securities – Domestic (b) 1,395.3 — — — 1,395.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,407.6 1,057.1 — 10.2 2,474.9 Total Assets $ 1,771.4 $ 1,407.7 $ 353.6 $ (271.9 ) $ 3,260.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.2 $ 327.0 $ 185.6 $ (274.7 ) $ 242.1 Cash Flow Hedges: Commodity Hedges (c) — 24.8 36.8 (2.7 ) 58.9 Fair Value Hedges — 17.4 — — 17.4 Total Risk Management Liabilities $ 4.2 $ 369.2 $ 222.4 $ (277.4 ) $ 318.4 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) (f) 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) (f) $ 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 Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 156.7 $ — $ — $ — $ 156.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 0.7 $ — $ (0.5 ) $ 0.2 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 25.6 $ — $ — $ — $ 25.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) 0.1 59.1 58.3 (59.4 ) 58.1 Total Assets $ 25.7 $ 59.1 $ 58.3 $ (59.4 ) $ 83.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.2 $ 58.4 $ 0.5 $ (58.5 ) $ 0.6 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 42.1 $ 10.3 $ (43.2 ) $ 9.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 12.3 — — 10.2 22.5 Fixed Income Securities: United States Government — 996.1 — — 996.1 Corporate Debt — 52.4 — — 52.4 State and Local Government — 8.6 — — 8.6 Subtotal Fixed Income Securities — 1,057.1 — — 1,057.1 Equity Securities – Domestic (b) 1,395.3 — — — 1,395.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,407.6 1,057.1 — 10.2 2,474.9 Total Assets $ 1,407.6 $ 1,099.2 $ 10.3 $ (33.0 ) $ 2,484.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.1 $ 41.2 $ 1.4 $ (42.3 ) $ 0.4 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 27.6 $ — $ — $ — $ 27.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 99.4 $ (0.6 ) $ 99.6 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 10.8 $ (0.4 ) $ 10.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 1.3 $ (0.6 ) $ 1.0 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 ) $ — SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 5.6 $ (0.8 ) $ 4.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 3.3 $ (1.1 ) $ 2.6 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 (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, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(4) million in 2019, $1 million in periods 2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $108 million in 2019, $37 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032. 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, 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 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2018 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2017 $ 40.3 $ 24.7 $ 7.6 $ (132.4 ) $ 6.2 $ 5.9 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 148.9 104.1 14.2 1.8 18.1 (4.8 ) Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 9.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 15.7 — — — — — Settlements (214.0 ) (127.9 ) (21.3 ) 4.6 (24.3 ) (2.1 ) Transfers into Level 3 (d) (e) 15.8 — — — — — Transfers out of Level 3 (e) (1.6 ) — (0.3 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 116.3 56.9 8.7 26.6 9.5 3.3 Balance as of December 31, 2018 $ 131.2 $ 57.8 $ 8.9 $ (99.4 ) $ 9.5 $ 2.3 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 (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.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2018 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 257.1 $ 212.5 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 176.57 $ 33.07 Natural Gas Contracts — 2.5 Discounted Cash Flow Forward Market Price (b) 2.18 3.54 2.47 FTRs 96.5 7.4 Discounted Cash Flow Forward Market Price (a) (11.68 ) 17.79 1.09 Total $ 353.6 $ 222.4 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 Natural Gas Contracts — 0.2 Discounted Cash Flow Forward Market Price (b) 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, 2018 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.4 $ 0.5 Discounted Cash Flow Forward Market Price $ 16.82 $ 62.65 $ 37.00 FTRs 55.9 — Discounted Cash Flow Forward Market Price 0.10 15.16 3.27 Total $ 58.3 $ 0.5 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, 2018 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.4 $ 0.9 Discounted Cash Flow Forward Market Price $ 16.82 $ 62.65 $ 37.00 FTRs 8.9 0.5 Discounted Cash Flow Forward Market Price (2.11 ) 6.21 1.06 Total $ 10.3 $ 1.4 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, 2018 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ — $ 99.4 Discounted Cash Flow Forward Market Price $ 26.29 $ 62.74 $ 42.50 Significant Unobservable Inputs December 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ — $ 132.4 Discounted Cash Flow Forward Market Price $ 30.52 $ 170.43 $ 44.62 Significant Unobservable Inputs December 31, 2018 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 10.8 $ 1.3 Discounted Cash Flow Forward Market Price $ (11.68 ) $ 10.30 $ (1.40 ) 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, 2018 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 2.5 Discounted Cash Flow Forward Market Price (b) $ 2.18 $ 3.54 $ 2.47 FTRs 5.6 0.8 Discounted Cash Flow Forward Market Price (a) (11.68 ) 10.30 (1.40 ) Total $ 5.6 $ 3.3 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 (b) $ 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 (a) Represents market prices in dollars per MWh. (b) 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)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Status of Tax Reform Regulatory Proceedings	Registrant (Jurisdiction) Change in Tax Rate Excess ADIT Subject to Normalization Requirements Excess ADIT Not Subject to Normalization Requirements AEP Texas (Texas-Distribution) Order Issued Order Issued Order Issued – Partial (a) AEP Texas (Texas-Transmission) Order Issued To be addressed in a later filing To be addressed in a later filing APCo (Virginia) Legislation Enacted – Case Pending (b) Legislation Enacted – Case Pending (b) Order Issued – Partial; Separate Case Pending (c) I&M (Michigan) Order Issued Case Pending Case Pending SWEPCo (Louisiana) Case Pending – Rates Implemented (d) Case Pending – Rates Implemented (d) Case Pending – Rates Implemented (d) SWEPCo (Texas) Order Issued To be addressed in a later filing To be addressed in a later filing PJM FERC Transmission Settlement Approved (e) Settlement Approved (e) Settlement Approved (e) SPP FERC Transmission To be addressed in a later filing To be addressed in a later filing To be addressed in a later filing (a) A portion of the Excess ADIT that is not subject to rate normalization requirements is to be addressed in a later filing. (b) Legislation has been issued for a blanket amount that is subject to true-up and final commission approval. (c) In October 2018, the Virginia SCC issued an order approving APCo’s request to refund a portion of the Excess ADIT that is not subject to rate normalization requirements to customers. The remainder is to be addressed in a separate pending case. (d) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval. (e) An ALJ has approved a settlement. The settlement is subject to final FERC ruling.
Details of Income Taxes as Reported	Year Ended December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (31.7 ) $ 37.0 $ (14.2 ) $ (31.9 ) $ 60.9 $ 55.6 $ 35.6 $ 18.3 Deferred 112.8 (16.4 ) 82.3 (24.6 ) (44.1 ) (36.9 ) (34.7 ) (0.5 ) Deferred Investment Tax Credits 9.2 (1.5 ) — 0.1 (4.7 ) — (2.0 ) (1.4 ) Total Federal 90.3 19.1 68.1 (56.4 ) 12.1 18.7 (1.1 ) 16.4 State and Local: Current 30.8 1.8 (0.6 ) 3.7 15.8 4.6 (0.2 ) 2.3 Deferred (8.5 ) (0.1 ) 16.6 7.8 1.2 0.7 3.6 1.7 Deferred Investment Tax Credits 2.7 — — — — — 2.7 — Total State and Local 25.0 1.7 16.0 11.5 17.0 5.3 6.1 4.0 Income Tax Expense (Benefit) Before Discontinued Operations $ 115.3 $ 20.8 $ 84.1 $ (44.9 ) $ 29.1 $ 24.0 $ 5.0 $ 20.4 Year Ended December 31, 2017 AEP AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (4.0 ) $ (85.7 ) $ (130.4 ) $ 15.3 $ (106.5 ) $ 11.2 $ (77.1 ) $ (30.1 ) Deferred 856.6 63.3 254.8 166.9 202.1 141.3 122.7 84.8 Deferred Investment Tax Credits 48.6 (1.6 ) — (0.1 ) (4.7 ) — (1.6 ) (1.4 ) Total Federal 901.2 (24.0 ) 124.4 182.1 90.9 152.5 44.0 53.3 State and Local: Current 16.0 0.6 1.1 (1.4 ) (8.1 ) 0.2 (0.2 ) (0.9 ) Deferred 44.9 — 16.7 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 17.8 3.2 (9.5 ) 6.8 6.1 (5.2 ) Income Tax Expense (Benefit) Before Discontinued Operations $ 969.7 $ (23.4 ) $ 142.2 $ 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 (Benefit) Before Discontinued Operations $ (73.7 ) $ 59.9 $ 94.1 $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	AEP Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 1,931.3 $ 1,928.9 $ 618.0 Less: Equity Earnings – Dolet Hills (2.7 ) — — Discontinued Operations (Net of Income Tax of $0, $0 and $0 in 2018, 2017 and 2016, Respectively) — — 2.5 Income Tax Expense (Benefit) Before Discontinued Operations 115.3 969.7 (73.7 ) Pretax Income $ 2,043.9 $ 2,898.6 $ 546.8 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 429.2 $ 1,014.5 $ 191.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 24.4 60.2 41.7 Investment Tax Credit Amortization (20.2 ) (18.8 ) (12.3 ) State and Local Income Taxes, Net 19.7 54.7 (20.7 ) Removal Costs (19.8 ) (32.7 ) (39.8 ) AFUDC (29.4 ) (37.4 ) (44.8 ) Valuation Allowance — (1.8 ) (128.3 ) U.K. Windfall Tax — — (12.9 ) Tax Reform Adjustments (10.9 ) (26.7 ) — Tax Adjustments — (35.8 ) (43.9 ) Tax Reform Excess ADIT Reversal (257.2 ) — — Other (20.5 ) (6.5 ) (4.1 ) Income Tax Expense (Benefit) Before Discontinued Operations $ 115.3 $ 969.7 $ (73.7 ) Effective Income Tax Rate 5.6 % 33.5 % (13.5 ) % AEP Texas Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 211.3 $ 310.5 $ 146.6 Discontinued Operations (Net of Income Tax of $0, $0 and $27.6 in 2018, 2017 and 2016, Respectively) — — 48.8 Income Tax Expense (Benefit) 20.8 (23.4 ) 59.9 Pretax Income $ 232.1 $ 287.1 $ 255.3 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 48.7 $ 100.5 $ 89.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: State and Local Income Taxes, Net 1.3 0.4 (6.0 ) AFUDC (4.2 ) (3.9 ) (3.2 ) Parent Company Loss Benefit (3.1 ) — (2.5 ) Tax Reform Adjustments (11.0 ) (117.4 ) — Tax Adjustments — (4.2 ) (4.9 ) U.K. Windfall Tax — — (12.9 ) Tax Reform Excess ADIT Reversal (11.8 ) — — Other 0.9 1.2 — Income Tax Expense (Benefit) Before Discontinued Operations $ 20.8 $ (23.4 ) $ 59.9 Effective Income Tax Rate 9.0 % (8.2 ) % 23.5 % AEPTCo Years Ended December 31, 2018 2017 (a) 2016 (in millions) Net Income $ 315.9 $ 270.7 $ 192.7 Income Tax Expense 84.1 142.2 94.1 Pretax Income $ 400.0 $ 412.9 $ 286.8 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 84.0 $ 144.5 $ 100.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: AFUDC (14.1 ) (17.0 ) (18.3 ) State and Local Income Taxes, Net 12.6 13.1 11.4 Tax Reform Adjustments — 0.6 — Other 1.6 1.0 0.6 Income Tax Expense $ 84.1 $ 142.2 $ 94.1 Effective Income Tax Rate 21.0 % 34.4 % 32.8 % (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. APCo Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 367.8 $ 331.3 $ 369.1 Income Tax Expense (Benefit) (44.9 ) 185.3 199.1 Pretax Income $ 322.9 $ 516.6 $ 568.2 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 67.8 $ 180.8 $ 198.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.5 18.0 19.3 State and Local Income Taxes, Net 9.1 3.5 6.0 Removal Costs (9.6 ) (12.4 ) (12.0 ) AFUDC (4.3 ) (5.0 ) (6.1 ) Tax Reform Adjustments 0.1 4.3 — Tax Reform Excess ADIT Reversal (108.5 ) — — Other (8.0 ) (3.9 ) (7.0 ) Income Tax Expense (Benefit) $ (44.9 ) $ 185.3 $ 199.1 Effective Income Tax Rate (13.9 ) % 35.9 % 35.0 % I&M Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 261.3 $ 186.7 $ 239.9 Income Tax Expense 29.1 81.4 67.5 Pretax Income $ 290.4 $ 268.1 $ 307.4 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 61.0 $ 93.8 $ 107.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation (0.7 ) 11.4 6.7 Investment Tax Credit Amortization (4.7 ) (4.7 ) (4.7 ) State and Local Income Taxes, Net 13.4 (1.0 ) 2.4 Removal Costs (8.0 ) (13.3 ) (21.3 ) AFUDC (2.5 ) (5.6 ) (7.3 ) Tax Adjustments — 2.7 (14.2 ) Tax Reform Adjustments — (2.9 ) — Tax Reform Excess ADIT Reversal (25.8 ) — — Other (3.6 ) 1.0 (1.7 ) Income Tax Expense $ 29.1 $ 81.4 $ 67.5 Effective Income Tax Rate 10.0 % 30.4 % 22.0 % OPCo Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 325.5 $ 323.9 $ 282.2 Income Tax Expense 24.0 159.3 143.8 Pretax Income $ 349.5 $ 483.2 $ 426.0 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 73.4 $ 169.1 $ 149.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 2.6 7.6 7.1 State and Local Income Taxes, Net 4.2 4.4 3.8 Tax Reform Adjustments — (14.4 ) — Tax Reform Excess ADIT Reversal (51.0 ) — — Parent Company Loss Benefit (5.5 ) (0.2 ) (7.2 ) Other 0.3 (7.2 ) (9.0 ) Income Tax Expense $ 24.0 $ 159.3 $ 143.8 Effective Income Tax Rate 6.9 % 33.0 % 33.8 % PSO Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 83.2 $ 72.0 $ 100.0 Income Tax Expense 5.0 50.1 54.4 Pretax Income $ 88.2 $ 122.1 $ 154.4 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 18.5 $ 42.7 $ 54.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 1.0 0.3 0.8 Investment Tax Credit Amortization (1.7 ) (1.6 ) (1.4 ) Parent Company Loss Benefit (1.4 ) — — State and Local Income Taxes, Net 4.8 4.0 4.2 Tax Reform Adjustments — 2.8 — Tax Reform Excess ADIT Reversal (15.5 ) — — Other (0.7 ) 1.9 (3.2 ) Income Tax Expense $ 5.0 $ 50.1 $ 54.4 Effective Income Tax Rate 5.7 % 41.0 % 35.2 % SWEPCo Years Ended December 31, 2018 2017 2016 (in millions) Net Income $ 152.2 $ 137.5 $ 169.7 Less: Equity Earnings – Dolet Hills (2.7 ) — — Income Tax Expense 20.4 48.1 52.1 Pretax Income $ 169.9 $ 185.6 $ 221.8 Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively) $ 35.7 $ 65.0 $ 77.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.4 1.9 3.2 Depletion (3.2 ) (5.7 ) (5.5 ) State and Local Income Taxes, Net 3.2 (2.3 ) (14.7 ) AFUDC (1.3 ) (0.9 ) (3.9 ) Tax Adjustments — (9.9 ) (0.9 ) Tax Reform Adjustments — (0.4 ) — Tax Reform Excess ADIT Reversal (16.0 ) — — Other (1.4 ) 0.4 (3.7 ) Income Tax Expense $ 20.4 $ 48.1 $ 52.1 Effective Income Tax Rate 12.0 % 25.9 % 23.5 %
Reconciliation of Significant Temporary Differences	AEP December 31, 2018 2017 (in millions) Deferred Tax Assets $ 2,750.8 $ 3,504.6 Deferred Tax Liabilities (9,837.3 ) (10,318.5 ) Net Deferred Tax Liabilities $ (7,086.5 ) $ (6,813.9 ) Property Related Temporary Differences $ (6,224.8 ) $ (5,680.6 ) Amounts Due to Customers for Future Federal Income Taxes 1,117.1 1,064.8 Deferred State Income Taxes (a) (859.9 ) (1,124.4 ) Securitized Assets (186.6 ) (257.7 ) Regulatory Assets (454.1 ) (500.3 ) Deferred Income Taxes on Other Comprehensive Loss 32.0 25.7 Accrued Nuclear Decommissioning (453.7 ) (457.0 ) Net Operating Loss Carryforward 78.3 86.6 Tax Credit Carryforward 113.7 174.7 Investment in Partnership (300.5 ) (222.0 ) All Other, Net 52.0 76.3 Net Deferred Tax Liabilities $ (7,086.5 ) $ (6,813.9 ) (a) In 2018, AEP recorded a $233 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. AEP Texas December 31, 2018 2017 (in millions) Deferred Tax Assets $ 208.1 $ 221.0 Deferred Tax Liabilities (1,121.2 ) (1,134.1 ) Net Deferred Tax Liabilities $ (913.1 ) $ (913.1 ) Property Related Temporary Differences $ (836.3 ) $ (791.5 ) Amounts Due to Customers for Future Federal Income Taxes 140.6 140.9 Deferred State Income Taxes (27.1 ) (27.5 ) Regulatory Assets (53.9 ) (36.4 ) Securitized Transition Assets (134.7 ) (190.5 ) Deferred Income Taxes on Other Comprehensive Loss 4.0 4.1 Deferred Revenues 4.6 10.9 All Other, Net (10.3 ) (23.1 ) Net Deferred Tax Liabilities $ (913.1 ) $ (913.1 ) AEPTCo December 31, 2018 2017 (a) (in millions) Deferred Tax Assets $ 142.9 $ 163.0 Deferred Tax Liabilities (847.3 ) (763.4 ) Net Deferred Tax Liabilities $ (704.4 ) $ (600.4 ) Property Related Temporary Differences $ (755.0 ) $ (653.4 ) Amounts Due to Customers for Future Federal Income Taxes 101.6 89.7 Deferred State Income Taxes (b) (51.9 ) (77.4 ) Deferred Federal Income Taxes on Deferred State Income Taxes — 16.3 Net Operating Loss Carryforward 13.4 16.8 Tax Credit Carryforward — 0.3 All Other, Net (12.5 ) 7.3 Net Deferred Tax Liabilities $ (704.4 ) $ (600.4 ) (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information. (b) In 2018, AEPTCo recorded a $21 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. APCo December 31, 2018 2017 (in millions) Deferred Tax Assets $ 475.2 $ 614.4 Deferred Tax Liabilities (2,101.0 ) (2,180.1 ) Net Deferred Tax Liabilities $ (1,625.8 ) $ (1,565.7 ) Property Related Temporary Differences $ (1,393.6 ) $ (1,308.2 ) Amounts Due to Customers for Future Federal Income Taxes 224.2 228.0 Deferred State Income Taxes (a) (280.3 ) (335.7 ) Regulatory Assets (73.8 ) (83.9 ) Securitized Assets (54.3 ) (59.3 ) Deferred Income Taxes on Other Comprehensive Loss 1.3 (0.4 ) Tax Credit Carryforward 0.2 16.6 All Other, Net (49.5 ) (22.8 ) Net Deferred Tax Liabilities $ (1,625.8 ) $ (1,565.7 ) (a) In 2018, APCo recorded a $51 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. I&M December 31, 2018 2017 (in millions) Deferred Tax Assets $ 771.6 $ 1,096.4 Deferred Tax Liabilities (1,719.6 ) (2,050.2 ) Net Deferred Tax Liabilities $ (948.0 ) $ (953.8 ) Property Related Temporary Differences $ (445.0 ) $ (403.0 ) Amounts Due to Customers for Future Federal Income Taxes 142.0 137.6 Deferred State Income Taxes (a) (139.7 ) (180.6 ) Deferred Income Taxes on Other Comprehensive Loss 3.7 3.9 Accrued Nuclear Decommissioning (453.7 ) (457.0 ) Regulatory Assets (31.9 ) (43.8 ) Net Operating Loss Carryforward 0.2 1.6 All Other, Net (23.6 ) (12.5 ) Net Deferred Tax Liabilities $ (948.0 ) $ (953.8 ) (a) In 2018, I&M recorded a $48 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. OPCo December 31, 2018 2017 (in millions) Deferred Tax Assets $ 209.0 $ 286.0 Deferred Tax Liabilities (972.3 ) (1,048.9 ) Net Deferred Tax Liabilities $ (763.3 ) $ (762.9 ) Property Related Temporary Differences $ (826.9 ) $ (761.2 ) Amounts Due to Customers for Future Federal Income Taxes 130.9 127.3 Deferred State Income Taxes (26.8 ) (41.7 ) Regulatory Assets (55.0 ) (107.7 ) Deferred Income Taxes on Other Comprehensive Loss (0.3 ) (0.6 ) Deferred Fuel and Purchased Power (1.6 ) (24.5 ) All Other, Net 16.4 45.5 Net Deferred Tax Liabilities $ (763.3 ) $ (762.9 ) PSO December 31, 2018 2017 (in millions) Deferred Tax Assets $ 229.6 $ 269.2 Deferred Tax Liabilities (837.4 ) (911.2 ) Net Deferred Tax Liabilities $ (607.8 ) $ (642.0 ) Property Related Temporary Differences $ (609.4 ) $ (623.8 ) Amounts Due to Customers for Future Federal Income Taxes 107.1 111.6 Deferred State Income Taxes (a) (103.8 ) (142.7 ) Regulatory Assets (32.3 ) (34.4 ) Deferred Income Taxes on Other Comprehensive Loss (0.6 ) (0.8 ) Deferred Federal Income Taxes on Deferred State Income Taxes — 33.5 Net Operating Loss Carryforward 16.4 23.1 Tax Credit Carryforward — 0.7 All Other, Net 14.8 (9.2 ) Net Deferred Tax Liabilities $ (607.8 ) $ (642.0 ) (a) In 2018, PSO recorded a $33 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018. SWEPCo December 31, 2018 2017 (in millions) Deferred Tax Assets $ 317.4 $ 349.4 Deferred Tax Liabilities (1,220.2 ) (1,267.1 ) Net Deferred Tax Liabilities $ (902.8 ) $ (917.7 ) Property Related Temporary Differences $ (929.1 ) $ (908.8 ) Amounts Due to Customers for Future Federal Income Taxes 145.8 135.8 Deferred State Income Taxes (a) (156.0 ) (189.2 ) Regulatory Assets (30.8 ) (30.8 ) Deferred Income Taxes on Other Comprehensive Loss 1.4 1.3 Capital/Impairment Loss - Turk Plant 15.8 17.4 Net Operating Loss Carryforward 36.2 38.7 Tax Credit Carryforward — 0.8 All Other, Net 13.9 17.1 Net Deferred Tax Liabilities $ (902.8 ) $ (917.7 ) (a) In 2018, SWEPCo recorded a $38 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.
State Net Income Tax Operating Loss Carryforwards	State Net Income Tax Operating Loss Years of Company State/Municipality Carryforward Expiration (in millions) AEP Arkansas $ 67.8 2018 - 2023 AEP Kentucky 130.4 2025 - 2037 AEP Louisiana 517.3 2030 - 2038 AEP Oklahoma 644.2 2032 - 2037 AEP Tennessee 28.6 2025 - 2033 AEP Virginia 22.8 2030 - 2038 AEP West Virginia 5.1 2029 - 2037 AEP Ohio Municipal 226.5 2019 - 2023 AEPTCo Oklahoma 264.0 2032 - 2037 AEPTCo Ohio Municipal 43.6 2019 - 2023 I&M West Virginia 3.8 2032 - 2037 PSO Oklahoma 348.8 2034 - 2037 SWEPCo Arkansas 67.1 2021 - 2023 SWEPCo Louisiana 504.9 2032 - 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 $ 113.7 $ 100.9 $ 34.2 $ — APCo 0.2 — — — I&M 0.9 — — — PSO — — 34.2 —
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, 2018 $ 86.6 $ (0.8 ) $ — $ — $ 3.2 $ 6.9 $ — $ (0.8 ) Increase – Tax Positions Taken During a Prior Period 0.1 — — — — — — — Decrease – Tax Positions Taken During a Prior Period — — — — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — — — Decrease – Settlements with Taxing Authorities (71.0 ) — — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (1.1 ) — — — — — — — Balance as of December 31, 2018 $ 14.6 $ (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, 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
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2018 2017 2016 (in millions) AEP $ 11.6 $ 10.5 $ 15.8 AEP Texas (0.7 ) (0.5 ) 4.2 AEPTCo — — — APCo — — — I&M 2.6 2.1 2.5 OPCo 5.4 4.5 4.4 PSO — — 0.1 SWEPCo (0.6 ) (0.5 ) 0.8

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2018
Lease Rental Costs	Year Ended December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 245.0 $ 13.6 $ 2.7 $ 18.2 $ 89.2 $ 10.7 $ 5.7 $ 6.5 Amortization of Capital Leases 62.4 4.8 0.1 7.0 6.6 3.9 3.2 11.2 Interest on Capital Leases 16.4 1.2 — 3.0 3.3 0.5 0.4 3.2 Total Lease Rental Costs $ 323.8 $ 19.6 $ 2.8 $ 28.2 $ 99.1 $ 15.1 $ 9.3 $ 20.9 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 (a) Amounts include lease expenses related to Desert Sky and Trent that were classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for the year ended December 31, 2016. See Note 7 - Dispositions and Impairments for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 131.3 $ — $ — $ 38.7 $ 27.0 $ — $ 2.6 $ 34.3 Other Property, Plant and Equipment 373.9 38.8 0.2 17.3 33.3 20.4 17.6 119.8 Total Property, Plant and Equipment 505.2 38.8 0.2 56.0 60.3 20.4 20.2 154.1 Accumulated Amortization 226.4 10.3 0.1 16.2 21.6 8.3 7.9 99.9 Net Property, Plant and Equipment Under Capital Leases $ 278.8 $ 28.5 $ 0.1 $ 39.8 $ 38.7 $ 12.1 $ 12.3 $ 54.2 Obligations Under Capital Leases: Noncurrent Liability $ 233.5 $ 24.0 $ — $ 33.7 $ 33.4 $ 9.2 $ 9.5 $ 50.6 Liability Due Within One Year 55.5 4.5 0.1 6.1 5.3 2.9 2.8 10.2 Total Obligations Under Capital Leases $ 289.0 $ 28.5 $ 0.1 $ 39.8 $ 38.7 $ 12.1 $ 12.3 $ 60.8 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
Future Minimum Lease Payments	Capital Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 70.8 $ 5.8 $ 0.1 $ 9.0 $ 8.2 $ 3.3 $ 3.4 $ 13.1 2020 60.2 5.3 — 8.0 7.2 2.7 2.6 11.5 2021 51.7 4.7 — 7.3 6.6 2.3 2.0 10.5 2022 43.8 4.2 — 6.8 6.1 1.7 1.6 9.4 2023 35.5 3.7 — 6.3 5.7 1.2 1.4 8.6 Later Years 90.2 10.1 — 13.3 21.7 2.8 3.3 18.7 Total Future Minimum Lease Payments 352.2 33.8 0.1 50.7 55.5 14.0 14.3 71.8 Less Estimated Interest Element 63.2 5.3 — 10.9 16.8 1.9 2.0 11.0 Estimated Present Value of Future Minimum Lease Payments $ 289.0 $ 28.5 $ 0.1 $ 39.8 $ 38.7 $ 12.1 $ 12.3 $ 60.8 Noncancelable Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 259.6 $ 15.1 $ 2.3 $ 17.6 $ 92.6 $ 14.5 $ 6.5 $ 7.4 2020 250.1 14.1 1.8 16.5 89.3 13.2 6.0 7.2 2021 232.7 13.2 1.0 13.9 84.8 10.9 5.0 6.7 2022 222.5 12.2 0.5 12.8 83.8 10.0 4.6 6.1 2023 58.3 10.8 0.1 9.9 6.5 8.8 4.1 5.0 Later Years 165.2 28.4 — 20.5 19.5 31.7 10.7 11.7 Total Future Minimum Lease Payments $ 1,188.4 $ 93.8 $ 5.7 $ 91.2 $ 376.5 $ 89.1 $ 36.9 $ 44.1
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 47.7 AEP Texas 10.8 APCo 8.8 I&M 3.7 OPCo 7.9 PSO 3.8 SWEPCo 4.3
Rockport Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 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 $ 590.6 $ 295.3 (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, 2018
AEP Common Stock	Shares of AEP Common Stock Issued Held in Treasury 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 Issued 1,239,392 — Treasury Stock Reissued — (886 ) (a) Balance, December 31, 2018 513,450,036 20,204,160 (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, 2018 2018 2017 2018 2017 AEP (in millions) Senior Unsecured Notes 2018-2048 4.36% 2.15%-8.13% 2.15%-8.13% $ 18,903.3 $ 16,478.3 Pollution Control Bonds (a) 2018-2038 (b) 3.14% 1.60%-6.30% 1.54%-6.30% 1,643.8 1,621.7 Notes Payable – Nonaffiliated (c) 2019-2032 3.95% 3.20%-6.37% 2.03%-6.37% 204.7 260.8 Securitization Bonds 2018-2028 (d) 3.65% 1.98%-5.31% 1.98%-5.31% 1,111.4 1,416.5 Spent Nuclear Fuel Obligation (e) 273.6 268.6 Other Long-term Debt 2018-2059 3.72% 1.15%-13.718% 1.15%-13.718% 1,209.9 1,127.4 Total Long-term Debt Outstanding $ 23,346.7 $ 21,173.3 AEP Texas Senior Unsecured Notes 2018-2047 4.06% 2.40%-6.76% 2.40%-6.76% $ 2,398.4 $ 1,932.2 Pollution Control Bonds 2020-2030 4.39% 1.75%-6.30% 1.75%-6.30% 490.9 490.5 Securitization Bonds 2018-2024 (d) 3.95% 1.98%-5.31% 1.98%-5.31% 791.2 1,026.1 Other Long-term Debt 2019-2059 3.94% 3.94%-4.50% 2.75%-4.50% 200.8 200.5 Total Long-term Debt Outstanding $ 3,881.3 $ 3,649.3 AEPTCo Senior Unsecured Notes 2018-2048 3.92% 2.68%-5.52% 2.68%-5.52% $ 2,823.0 $ 2,550.4 Total Long-term Debt Outstanding $ 2,823.0 $ 2,550.4 APCo Senior Unsecured Notes 2021-2045 5.20% 3.30%-7.00% 3.30%-7.00% $ 3,047.3 $ 3,045.1 Pollution Control Bonds (a) 2018-2038 (b) 2.64% 1.70%-5.38% 1.625%-5.38% 616.0 512.2 Securitization Bonds 2023-2028 (d) 3.06% 2.008%-3.772% 2.008%-3.772% 272.3 295.9 Other Long-term Debt 2019-2026 3.91% 3.74%-13.718% 2.73%-13.718% 127.0 126.9 Total Long-term Debt Outstanding $ 4,062.6 $ 3,980.1 I&M Senior Unsecured Notes 2019-2048 4.38% 3.20%-6.05% 3.20%-7.00% $ 2,149.0 $ 1,809.0 Pollution Control Bonds (a) 2018-2025 (b) 2.49% 1.81%-3.05% 1.75%-2.75% 264.5 264.6 Notes Payable – Nonaffiliated (c) 2019-2022 3.30% 3.20%-3.38% 2.03%-2.19% 135.8 188.6 Spent Nuclear Fuel Obligation (e) 273.6 268.6 Other Long-term Debt 2018-2025 3.80% 3.66%-6.00% 2.82%-6.00% 212.5 214.3 Total Long-term Debt Outstanding $ 3,035.4 $ 2,745.1 OPCo Senior Unsecured Notes 2018-2048 5.52% 4.15%-6.60% 5.375%-6.60% $ 1,635.5 $ 1,591.4 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.3 Securitization Bonds 2019 (d) 2.049% 2.049% 2.049% 47.8 94.5 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.0 1.1 Total Long-term Debt Outstanding $ 1,716.6 $ 1,719.3 PSO Senior Unsecured Notes 2019-2046 4.80% 3.05%-6.625% 3.05%-6.625% $ 1,144.9 $ 1,144.1 Pollution Control Bonds 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2019-2027 3.70% 3.00%-3.72% 2.584%-3.00% 129.5 129.8 Total Long-term Debt Outstanding $ 1,287.0 $ 1,286.5 SWEPCo Senior Unsecured Notes 2018-2048 4.04% 2.75%-6.20% 2.75%-6.45% $ 2,427.0 $ 2,110.7 Pollution Control Bonds 2018-2019 1.60% 1.60% 1.60%-4.95% 53.5 135.1 Notes Payable – Nonaffiliated (c) 2024-2032 5.23% 4.58%-6.37% 4.58%-6.37% 68.9 72.1 Other Long-term Debt 2020-2028 4.03% 3.75%-4.68% 2.925%-4.28% 164.0 124.0 Total Long-term Debt Outstanding $ 2,713.4 $ 2,441.9 (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 SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.
Long-term Debt 5-Year Maturity	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) 2019 $ 1,698.5 $ 501.1 $ 85.0 $ 430.7 $ 155.4 $ 47.9 $ 375.5 $ 59.7 2020 1,508.3 377.7 — 90.3 41.6 0.1 13.2 121.2 2021 1,961.5 66.2 50.0 393.0 256.4 500.1 250.5 6.2 2022 1,668.4 493.0 104.0 230.4 7.0 0.1 0.5 281.2 2023 539.6 195.0 60.0 26.6 252.4 0.1 0.5 6.2 After 2023 16,150.9 2,275.5 2,551.0 2,924.4 2,351.5 1,182.8 652.0 2,262.9 Principal Amount 23,527.2 3,908.5 2,850.0 4,095.4 3,064.3 1,731.1 1,292.2 2,737.4 Unamortized Discount, Net and Debt Issuance Costs (180.5 ) (27.2 ) (27.0 ) (32.8 ) (28.9 ) (14.5 ) (5.2 ) (24.0 ) Total Long-term Debt Outstanding $ 23,346.7 $ 3,881.3 $ 2,823.0 $ 4,062.6 $ 3,035.4 $ 1,716.6 $ 1,287.0 $ 2,713.4
Dividend Payment Restrictions	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Restricted Retained Earnings $ 1,591.4 (a) $ 353.7 $ — $ 17.6 $ 454.1 $ — $ 152.7 $ 526.4 (a) Includes the restrictions of consolidated and non-consolidated subsidiaries.
Lines of Credit and Short-term Debt	December 31, 2018 2017 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 2.16 % $ 718.0 1.22 % AEP Commercial Paper 1,160.0 2.96 % 898.6 1.85 % SWEPCo Notes Payable — — % 22.0 2.92 % Total Short-term Debt $ 1,910.0 $ 1,638.6 (a) Weighted-average interest 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, 2018 : 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, 2018 Limit (in millions) AEP Texas $ 390.6 $ 106.9 $ 176.0 $ 47.1 $ (216.0 ) $ 500.0 AEPTCo 371.3 276.4 177.9 58.4 35.8 795.0 (a) APCo 295.5 23.7 175.3 23.3 (182.6 ) 600.0 I&M 322.1 657.8 255.5 110.7 11.6 500.0 OPCo 270.8 225.0 167.8 189.4 (114.1 ) 500.0 PSO 193.7 31.8 104.5 12.9 (105.5 ) 300.0 SWEPCo 200.1 533.7 143.2 268.1 81.4 350.0 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 (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, 2018 : Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2018 (in millions) AEP Texas $ 8.4 $ 8.1 $ 8.0 SWEPCo 2.0 2.0 2.0 Year Ended December 31, 2017 : Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2017 (in millions) AEP Texas $ 8.6 $ 8.3 $ 8.4 SWEPCo 2.0 2.0 2.0
Direct Borrowing Activity	Year Ended December 31, 2018 : Maximum Maximum Average Average Borrowings From Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2018 December 31, 2018 Borrowing Limit (in millions) $ 1.2 $ 104.7 $ 1.1 $ 49.8 $ 1.2 $ 16.9 $ 75.0 (a) Year Ended December 31, 2017 : Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2017 December 31, 2017 Borrowing Limit (in millions) $ 4.1 $ 151.9 $ 1.1 $ 39.3 $ 1.1 $ 22.5 $ 75.0 (a) (a) 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, 2018 2017 2016 Maximum Interest Rate 2.97 % 1.85 % 1.02 % Minimum Interest Rate 1.81 % 0.92 % 0.69 %
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 the Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for the Years Ended December 31, Company 2018 2017 2016 2018 2017 2016 AEP Texas 2.26 % 1.29 % 0.88 % 2.29 % 1.26 % 0.72 % AEPTCo 2.27 % 1.36 % 0.85 % 2.10 % 1.27 % 0.83 % APCo 2.26 % 1.28 % 0.80 % 2.21 % 1.29 % 0.82 % I&M 2.16 % 1.27 % 0.80 % 2.08 % 1.29 % 0.80 % OPCo 2.18 % 1.37 % 0.85 % 2.47 % 0.98 % 0.74 % PSO 2.27 % 1.32 % 0.96 % 1.98 % — % 0.83 % SWEPCo 2.31 % 1.28 % 0.79 % 2.00 % 0.98 % 0.90 %
Maximum, Minimum and Average Interest Rates for Funds Borrowed from and Loaned to the Nonutility Money Pool	Year Ended December 31, 2018 : 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 — % — % 2.97 % 1.83 % — % 2.36 % SWEPCo — % — % 2.97 % 1.83 % — % 2.36 % 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 %
Maximum Minimum and Average Interest Rates for Funds Borrowed from and Loaned to AEP	Year Ended December 31, 2018 : 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 2.97 % 1.76 % 2.97 % 1.76 % 2.36 % 2.36 % 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 %
Comparative Accounts Receivable Information	Years Ended December 31, 2018 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 2.16 % 1.22 % 0.70 % Net Uncollectible Accounts Receivable Written Off $ 27.6 $ 23.4 $ 23.7
Customer Accounts Receivable Managed Portfolio	December 31, 2018 2017 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 972.5 $ 925.5 Short-term – Securitized Debt of Receivables 750.0 718.0 Delinquent Securitized Accounts Receivable 50.3 41.1 Bad Debt Reserves Related to Securitization 27.5 28.7 Unbilled Receivables Related to Securitization 281.4 303.2
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2018 2017 (in millions) APCo $ 133.3 $ 136.2 I&M 152.9 136.5 OPCo 395.2 367.4 PSO 109.7 115.1 SWEPCo 150.3 138.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 7.0 $ 5.6 $ 6.7 I&M 9.2 6.7 7.1 OPCo 26.3 21.7 28.9 PSO 7.9 7.0 6.2 SWEPCo 8.9 7.2 6.9
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 1,421.0 $ 1,372.8 $ 1,412.5 I&M 1,843.0 1,612.9 1,596.2 OPCo 2,674.5 2,339.0 2,633.0 PSO 1,484.6 1,337.0 1,269.3 SWEPCo 1,736.1 1,563.4 1,531.7

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Units and Reinvested Dividends on Outstanding Performance Units	Years Ended December 31, Performance Units 2018 2017 2016 Awarded Units (in thousands) (a) 581.4 590.7 597.4 Weighted Average Unit Fair Value at Grant Date $ 67.21 $ 69.78 $ 62.77 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2018 2017 2016 Awarded Units (in thousands) (b) 80.2 74.6 89.2 Weighted Average Fair Value at Grant Date $ 70.58 $ 72.35 $ 63.83 Vesting Period (in years) (c) (c) (c) (a) Awarded units in 2018 and 2017 were mezzanine equity awards and awarded units in 2016 were liability awards. (b) Awarded dividends in 2018 and 2017 were a mix of equity awards and liability awards, and all awarded dividends in 2016 were liability awards. (c) 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.
Summary of Performance Scores and Performance Units Earned	Years Ended December 31, Performance Units 2018 2017 2016 Certified Performance Score 136.7 % 164.8 % 163.9 % Performance Units Earned 820,780 956,055 1,111,966 Performance Units Mandatorily Deferred as AEP Career Shares 11,248 20,213 9,963 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 56,826 47,177 51,684 Performance Units to be Settled in Cash 752,706 888,665 1,050,319
Summary of Cash Payouts for Performance Units and Career Shares	Years Ended December 31, Performance Units and AEP Career Shares 2018 2017 2016 (in millions) Cash Settlements for Performance Units $ 66.9 $ 64.9 $ 62.7 Cash Settlements for Career Share Distributions — — 9.1 AEP Common Stock Settlements for Career Share Distributions 5.1 0.4 —
Status of Nonvested Performance Units	Nonvested Performance Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2018 587.5 $ 64.48 Granted 617.3 67.43 Vested — — Forfeited (33.5 ) 65.50 Nonvested as of December 31, 2018 1,171.3 66.01
Monte Carlo Valuation Assumptions	Years Ended December 31, Monte Carlo Valuation 2018 2017 Valuation Period (in years) (a) 2.87 2.86 Expected Volatility Minimum 14.77 % 15.65 % Expected Volatility Maximum 26.72 % 27.19 % Expected Volatility Average 17.90 % 19.07 % Dividend Rate (b) — % — % Risk Free Rate 2.34 % 1.44 % (a) Period from award date to vesting date. (b) Equivalent to reinvesting dividends.
Summary of Units Awarded and Fair Value of Restricted Stock Units	Years Ended December 31, Restricted Stock Units 2018 2017 2016 Awarded Units (in thousands) 260.0 255.8 242.0 Weighted Average Grant Date Fair Value $ 67.96 $ 65.26 $ 62.88
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	Years Ended December 31, Restricted Stock Units 2018 2017 2016 (in millions) Fair Value of Restricted Stock Units Vested $ 16.6 $ 16.1 $ 16.4 Intrinsic Value of Restricted Stock Units Vested (a) 19.2 20.0 21.0 (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, 2018 529.6 $ 62.13 Granted 260.0 67.96 Vested (277.5 ) 59.77 Forfeited (23.0 ) 64.84 Nonvested as of December 31, 2018 489.1 66.01
Stock Unit Accumulation Plan for Non-employee Directors	Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2018 2017 2016 Awarded Units (in thousands) 11.4 14.8 19.1 Weighted Average Grant Date Fair Value $ 70.41 $ 70.79 $ 64.96
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 2018 2017 2016 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 53.2 $ 79.5 $ 66.5 Actual Tax Benefit (b) 7.7 18.9 23.3 Total Compensation Cost Capitalized 19.7 26.4 20.8 (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 certain 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, 2018
Affiliated Revenues	Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2018 Direct Sales to East Affiliates $ — $ — $ 133.2 $ 0.1 $ — $ — $ — Direct Sales to West Affiliates — — — — — — — Auction Sales to OPCo (a) — — 5.8 7.1 — — — Direct Sales to AEPEP 103.6 — — — — — — Transmission Agreement and Transmission Coordination Agreement Sales — 591.4 36.4 11.7 3.9 0.9 26.9 Other Revenues 1.6 7.5 6.0 3.2 17.1 4.5 1.5 Total Affiliated Revenues $ 105.2 $ 598.9 $ 181.4 $ 22.1 $ 21.0 $ 5.4 $ 28.4 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 — 559.6 (b) 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 $ 568.1 $ 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 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
Affiliated Purchases	Related Party Purchases I&M OPCo PSO (in millions) Year Ended December 31, 2018 Auction Purchases from AEPEP (a) $ — $ 79.7 $ — Auction Purchases from AEP Energy (a) — 41.0 — Auction Purchases from AEPSC (a) — 14.6 — Direct Purchases from AEGCo 237.9 — — Total Affiliated Purchases $ 237.9 $ 135.3 $ — 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 (a) Refer to the Ohio Auctions section below for further information regarding this amount.
Transmission Agreement	Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 128.3 $ 158.2 $ 103.2 I&M 91.4 103.8 53.0 OPCo 210.1 248.6 143.6
Transmission Coordination Agreement	Years Ended December 31, Company 2018 2017 2016 (in millions) PSO $ 65.9 $ 56.0 $ 19.6 SWEPCo 10.5 6.6 (19.6 )
Joint License Agreement	Years Ended December 31, Billing Company 2018 2017 2016 (in millions) I&M $ 2.2 $ 1.4 $ 0.8 KPCo 0.2 0.2 0.1 OPCo 2.9 2.4 2.3 PSO 0.3 0.3 0.2
Railcar Maintenance	Years Ended December 31, Company 2018 2017 2016 (in millions) I&M $ 1.5 $ 1.3 $ 1.7 PSO 0.7 0.5 0.6 SWEPCo 3.4 3.5 3.3
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2018 2017 2016 (in millions) AEGCo $ 19.9 $ 15.3 $ 14.8 AGR — 0.1 0.3 APCo 35.1 37.2 36.9 KPCo 4.2 5.0 5.3 WPCo 4.2 5.0 4.8
Central Machine Shop	Years Ended December 31, Company 2018 2017 2016 (in millions) AGR $ 1.6 $ 1.2 $ 2.0 I&M 2.4 2.7 2.9 KPCo 1.7 1.8 1.5 PSO 0.5 1.1 0.5 SWEPCo 0.7 0.8 0.9
Related Party Sales of Property	Sales Years Ended December 31, Company 2018 2017 2016 (in millions) AEP Texas $ 0.3 $ 0.2 $ 0.3 APCo 5.4 3.5 4.5 I&M 8.2 5.0 5.2 OPCo 10.7 2.9 1.9 PSO 1.0 1.5 7.5 SWEPCo 0.8 0.5 1.0
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2018 2017 2016 (in millions) AEP Texas $ 0.1 $ 0.4 $ 0.7 AEPTCo 18.5 9.1 6.5 APCo 0.6 0.9 1.5 I&M 2.0 3.5 2.7 OPCo 2.8 1.6 1.7 PSO 1.3 0.2 3.2 SWEPCo 0.8 0.4 6.5

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2018
Consolidated Assets And Liabilities Of Variable Interest Entities	American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2018 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel AEP Texas Transition Funding OPCo APCo (in millions) ASSETS Current Assets $ 70.0 $ 77.6 $ 192.8 $ 29.5 $ 24.8 Net Property, Plant and Equipment 106.9 122.3 — — — Other Noncurrent Assets 98.5 58.4 683.5 (a) 24.2 (b) 261.8 (c) Total Assets $ 275.4 $ 258.3 $ 876.3 $ 53.7 $ 286.6 LIABILITIES AND EQUITY Current Liabilities $ 31.1 $ 77.1 $ 271.9 $ 48.5 $ 28.0 Noncurrent Liabilities 244.0 181.2 586.1 3.9 256.7 Equity 0.3 — 18.3 1.3 1.9 Total Liabilities and Equity $ 275.4 $ 258.3 $ 876.3 $ 53.7 $ 286.6 (a) Includes an intercompany item eliminated in consolidation of $47 million . (b) Includes an intercompany item eliminated in consolidation of $11 million . (c) Includes an intercompany item eliminated in consolidation of $3 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2018 Other Consolidated VIEs AEP Credit Protected Cell of EIS Transource Energy Desert Sky and Trent (in millions) ASSETS Current Assets $ 974.2 $ 177.8 $ 25.7 $ 6.8 Net Property, Plant and Equipment — — 380.3 348.5 Other Noncurrent Assets 6.3 0.1 1.9 — Total Assets $ 980.5 $ 177.9 $ 407.9 $ 355.3 LIABILITIES AND EQUITY Current Liabilities $ 923.5 $ 38.6 $ 19.9 $ 8.7 Noncurrent Liabilities 0.8 85.3 160.3 6.2 Equity 56.2 54.0 227.7 340.4 Total Liabilities and Equity $ 980.5 $ 177.9 $ 407.9 $ 355.3 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 $54 million . (b) Includes an intercompany item eliminated in consolidation of $33 million . (c) Includes an intercompany item eliminated in consolidation of $3 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
SWEPCo's Investment In DHLC	December 31, 2018 2017 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 14.5 14.5 11.8 11.8 SWEPCo’s Share of Obligations — 167.6 — 144.3 Total Investment in DHLC $ 22.1 $ 189.7 $ 19.4 $ 163.7
AEP's Investment In OVEC	December 31, 2018 2017 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) — 604.1 — 626.3 Total Investment in OVEC $ 4.4 $ 608.5 $ 4.4 $ 630.7 (a) Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $218 million , $109 million and $277 million as of December 31, 2018 and $226 million , $113 million and $287 million as of December 31, 2017 , respectively.
Purchased Power from OVEC	Years Ended December 31, Company 2018 2017 2016 (in millions) APCo $ 100.4 $ 101.0 $ 88.0 I&M 50.2 50.5 44.0 OPCo 127.5 128.2 111.7
AEP's Investment In PATH-WV	December 31, 2018 2017 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 (1.4 ) (1.4 ) (2.0 ) (2.0 ) Total Investment in PATH-WV $ 17.4 $ 17.4 $ 16.8 $ 16.8
Billings from Significant Variable Interest	Years Ended December 31, Company 2018 2017 2016 (in millions) AEP Texas $ 184.3 $ 152.6 $ 142.3 AEPTCo 220.4 188.9 131.1 APCo 295.6 268.8 244.2 I&M 173.5 176.0 147.7 OPCo 214.9 195.7 181.1 PSO 121.5 114.7 111.0 SWEPCo 164.4 150.7 147.0
Carrying Amount and Classification of Variable Interest in Accounts Payable	December 31, 2018 2017 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) AEP Texas $ 22.3 $ 22.3 $ 24.2 $ 24.2 AEPTCo 24.6 24.6 25.1 25.1 APCo 32.2 32.2 37.0 37.0 I&M 23.8 23.8 26.8 26.8 OPCo 23.9 23.9 27.4 27.4 PSO 13.2 13.2 18.7 18.7 SWEPCo 18.4 18.4 20.8 20.8

Property, Plant and Equipment_2

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment	December 31, 2018 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 20,989.1 (a) $ — $ — $ 6,509.6 $ 4,887.2 $ — $ 1,577.0 $ 4,672.6 (a) Transmission 21,500.5 3,683.6 6,515.8 3,317.7 1,576.8 2,544.3 892.3 1,866.9 Distribution 21,192.8 4,043.2 — 3,989.4 2,249.7 4,942.3 2,572.8 2,178.6 Other 3,770.8 724.6 172.6 457.4 543.1 563.7 298.1 485.2 CWIP 4,352.6 (a) 836.0 1,578.3 490.2 465.3 432.1 94.0 194.7 (a) Less: Accumulated Depreciation 17,743.1 1,431.2 271.9 4,118.9 3,139.4 2,217.7 1,472.1 2,633.5 Total Regulated Property, Plant and Equipment - Net 54,062.7 7,856.2 7,994.8 10,645.4 6,582.7 6,264.7 3,962.1 6,764.5 Nonregulated Property, Plant and Equipment - Net 1,036.4 135.6 1.4 22.9 28.5 10.2 4.6 107.3 Total Property, Plant and Equipment - Net $ 55,099.1 $ 7,991.8 $ 7,996.2 $ 10,668.3 $ 6,611.2 $ 6,274.9 $ 3,966.7 $ 6,871.8 December 31, 2017 AEP AEP Texas AEPTCo (b) 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 5,319.7 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 3,224.8 457.6 125.4 399.5 552.3 485.5 282.0 416.8 CWIP 3,972.6 (a) 834.4 1,324.0 483.0 460.2 410.1 111.3 220.7 (a) Less: Accumulated Depreciation 16,906.7 1,399.4 152.6 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 6,616.5 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 $ 6,617.9 $ 10,245.1 $ 6,050.4 $ 5,766.8 $ 3,886.2 $ 6,632.0 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
Depreciation, Depletion and Amortization - Regulated	AEP 2018 2017 2016 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% - 4.0% 20 - 132 2.3% - 3.7% 20 - 132 2.1% - 4.0% 35 - 132 Transmission 1.6% - 2.7% 15 - 81 1.6% - 2.7% 15 - 100 1.5% - 2.7% 15 - 100 Distribution 2.7% - 3.6% 7 - 78 2.7% - 3.7% 5 - 156 2.6% - 3.7% 7 - 156 Other 2.3% - 9.8% 5 - 75 2.3% - 9.2% 5 - 84 3.1% - 8.6% 5 - 84 AEP Texas 2018 2017 2016 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 1.7% 45 - 81 1.8% 45 - 81 Distribution 3.6% 7 - 70 3.6% 7 - 70 3.3% 7 - 70 Other 6.0% 5 - 50 8.7% 5 - 50 8.3% 5 - 50 AEPTCo 2018 2017 2016 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 1.9% 20 - 75 1.7% 20 - 100 1.6% 20 - 100 APCo 2018 2017 2016 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 - 112 3.1% 35 - 121 Transmission 1.6% 15 - 68 1.6% 15 - 68 1.5% 15 - 68 Distribution 3.6% 10 - 57 3.7% 10 - 57 3.7% 10 - 57 Other 7.4% 5 - 55 6.5% 5 - 55 6.0% 5 - 55 I&M 2018 2017 2016 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 3.4% 20 - 132 2.4% 20 - 132 2.4% 59 - 132 Transmission 1.8% 50 - 73 1.7% 50 - 75 1.7% 50 - 75 Distribution 3.1% 9 - 75 2.7% 10 - 70 2.8% 10 - 70 Other 8.9% 5 - 50 8.4% 5 - 45 8.6% 5 - 45 OPCo 2018 2017 2016 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 3.0% 14 - 65 2.8% 5 - 57 2.8% 7 - 57 Other 6.3% 5 - 50 6.2% 5 - 50 5.9% 5 - 50 PSO 2018 2017 2016 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 2.9% 35 - 75 2.4% 35 - 85 2.4% 35 - 85 Transmission 2.3% 45 - 75 2.2% 45 - 100 2.2% 45 - 100 Distribution 2.9% 15 - 78 2.7% 27 - 156 2.7% 27 - 156 Other 6.3% 5 - 64 7.4% 5 - 84 6.4% 5 - 84 SWEPCo 2018 2017 2016 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% 40 - 70 2.3% 40 - 70 2.1% 40 - 70 Transmission 2.2% 50 - 73 2.3% 50 - 73 2.2% 50 - 70 Distribution 2.7% 25 - 70 2.7% 25 - 70 2.6% 25 - 65 Other 8.0% 5 - 55 7.2% 5 - 55 6.8% 5 - 51
Depreciation, Depletion and Amortization - Unregulated	2018 2017 2016 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 3.4% - 22.3% 15 - 59 2.4% - 5.1% 15 - 66 2.8% - 17.2% 40 - 66 Transmission 2.4% 40 0.2% 40 2.3% 43 - 55 Distribution 2.3% 40 2.3% 40 1.3% 40 - 50 Other 16.3% 5 - 50 (a) 12.1% 5 - 50 (a) 9.1% 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, 2017 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates (a) ARO as of December 31, 2018 (in millions) AEP (b)(c)(d)(e) $ 2,005.7 $ 93.7 $ 0.8 $ (87.0 ) $ 342.3 (f) $ 2,355.5 AEP Texas (b)(e) 26.7 1.2 — (0.1 ) 0.1 27.9 APCo (b)(e) 125.0 6.6 — (17.3 ) 1.8 116.1 I&M (b)(c)(e) 1,321.8 58.7 — (0.2 ) 301.0 (f) 1,681.3 OPCo (e) 1.7 0.1 — — — 1.8 PSO (b)(e) 54.0 3.2 — (0.4 ) (9.9 ) 46.9 SWEPCo (b)(d)(e) 169.2 9.1 0.2 (11.7 ) 40.0 206.8 Company ARO as of December 31, 2016 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates (a) ARO as of December 31, 2017 (in millions) AEP (b)(c)(d)(e) $ 1,934.9 $ 90.9 $ 2.4 $ (104.5 ) $ 82.0 $ 2,005.7 AEP Texas (b)(e) 25.5 1.2 — (0.1 ) 0.1 26.7 APCo (b)(e) 127.1 7.0 — (21.7 ) 12.6 125.0 I&M (b)(c)(e) 1,258.1 55.9 — (0.1 ) 7.9 1,321.8 OPCo (e) 1.7 0.1 — (0.1 ) — 1.7 PSO (b)(e) 53.4 3.1 — (0.5 ) (2.0 ) 54.0 SWEPCo (b)(d)(e) 156.5 8.3 — (0.3 ) 4.7 169.2 (a) Primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs. (b) Includes ARO related to ash disposal facilities. (c) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.66 billion and $1.30 billion as of December 31, 2018 and 2017 , respectively. (d) Includes ARO related to Sabine and DHLC. (e) Includes ARO related to asbestos removal. (f) Revision for Cook Plant related to a new third-party study, which impacted the ARO liability for changes of estimated cash flows and application of a new discount rate.
Allowance For Equity Funds Used During Construction	Years Ended December 31, Company 2018 2017 2016 (in millions) AEP $ 132.5 $ 93.7 $ 113.2 AEP Texas 20.0 6.8 9.2 AEPTCo 70.6 49.0 (a) 52.3 APCo 13.2 9.2 11.7 I&M 11.9 11.1 15.3 OPCo 9.8 6.4 6.0 PSO 0.4 0.5 6.2 SWEPCo 6.0 2.4 11.0 (a) The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
Allowance For Borrowed Funds Used During Construction	Years Ended December 31, Company 2018 2017 2016 (in millions) AEP $ 73.6 $ 48.6 $ 51.7 AEP Texas 18.4 6.8 5.9 AEPTCo 26.1 20.2 15.6 APCo 8.4 5.3 6.3 I&M 7.4 6.7 7.2 OPCo 5.8 3.8 3.3 PSO 0.9 1.1 3.4 SWEPCo 4.8 2.1 6.9
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2018 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a)(i)(j) Coal 83.5 % $ 16.4 $ 0.2 $ 2.4 Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % 336.2 5.1 209.6 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 375.1 1.6 88.9 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 591.3 16.6 418.0 Oklaunion Power Station (f) Coal 70.3 % 106.4 — 67.8 Turk Generating Plant (h)(k) Coal 73.3 % 1,590.5 1.1 197.5 Total $ 3,015.9 $ 24.6 $ 984.2 AEP Texas Oklaunion Power Station (f) Coal 54.7 % $ 352.1 $ 0.2 $ 218.6 I&M Rockport Generating Plant (c)(d)(e) Coal 50.0 % $ 1,108.7 $ 50.2 $ 514.1 PSO Oklaunion Power Station (f) Coal 15.6 % $ 106.4 $ — $ 67.8 SWEPCo Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % $ 336.2 $ 5.1 $ 209.6 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 375.1 1.6 88.9 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 591.3 16.6 418.0 Turk Generating Plant (h)(k) Coal 73.3 % 1,590.5 1.1 197.5 Total $ 2,893.1 $ 24.4 $ 914.0 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)(i)(j) Coal 83.5 % $ 2.1 $ 4.2 $ 0.1 Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % 343.1 5.3 214.2 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 589.8 7.8 406.3 Oklaunion Power Station (f) Coal 70.3 % 456.4 1.9 254.6 Turk Generating Plant (h)(k) Coal 73.3 % 1,580.4 3.2 166.6 Transmission (l) NA (b) 62.7 0.3 46.1 Total $ 3,399.3 $ 31.6 $ 1,169.5 AEP Texas Oklaunion Power Station (f) Coal 54.7 % $ 350.7 $ 1.3 $ 194.1 I&M Rockport Generating Plant (c)(d)(e) Coal 50.0 % $ 1,093.9 $ 28.2 $ 562.6 PSO Oklaunion Power Station (f) Coal 15.6 % $ 105.7 $ 0.6 $ 60.5 SWEPCo Dolet Hills Power Station, Unit 1 (g) Lignite 40.2 % $ 343.1 $ 5.3 $ 214.2 Flint Creek Generating Station, Unit 1 (h) Coal 50.0 % 364.8 8.9 81.6 Pirkey Generating Station, Unit 1 (h) Lignite 85.9 % 589.8 7.8 406.3 Turk Generating Plant (h)(k) Coal 73.3 % 1,580.4 3.2 166.6 Total $ 2,878.1 $ 25.2 $ 868.7 (a) Operated by AGR. (b) Varying percentages of ownership. (c) Operated by I&M. (d) 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 . (e) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (f) 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 . (g) Operated by CLECO, a non-affiliated company. (h) Operated by SWEPCo. (i) Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. See the “Impairments” section of Note 7 . (j) 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% . (k) 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 . (l) In accordance with the 2017 CCD Transmission Asset Exchange Agreement between OPCo, Dayton Power & Light Company and Duke Energy Ohio, Inc., the parties agreed to an exchange and transfer of jointly owned transmission assets in order to eliminate the joint ownership of these assets. The asset exchange closed on June 30, 2018, ending the joint ownership of these transmission assets. NA Not applicable.

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2018
Changes in Carrying Amount of Goodwill	Corporate and Other Generation & Marketing AEP Consolidated (in millions) 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 Impairment Losses — — — Balance as of December 31, 2018 $ 37.1 $ 15.4 $ 52.5

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Disaggregated Revenues from Contracts with Customers	Year Ended December 31, 2018 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 578.9 $ — $ 1,342.6 $ 730.0 $ 1,611.5 $ 659.0 $ 641.5 Commercial Revenues 436.2 — 582.4 490.3 835.7 404.4 491.9 Industrial Revenues 110.0 — 602.4 560.3 385.2 294.1 325.8 Other Retail Revenues 25.9 — 77.4 7.2 12.9 83.3 8.6 Total Retail Revenues 1,151.0 — 2,604.8 1,787.8 2,845.3 1,440.8 1,467.8 Wholesale Revenues: Generation Revenues (a) — — 250.4 470.5 — 36.3 216.8 Transmission Revenues (b) 313.4 816.9 82.7 23.1 58.5 40.2 108.4 Total Wholesale Revenues 313.4 816.9 333.1 493.6 58.5 76.5 325.2 Other Revenues from Contracts with Customers (c) 28.6 15.1 55.3 99.6 176.1 19.1 24.0 Total Revenues from Contracts with Customers 1,493.0 832.0 2,993.2 2,381.0 3,079.9 1,536.4 1,817.0 Other Revenues: Alternative Revenues (d) (1.3 ) (55.9 ) (23.8 ) (2.1 ) (20.8 ) 10.9 4.9 Other Revenues (d) 103.6 — (1.9 ) (8.2 ) 4.3 — — Total Other Revenues 102.3 (55.9 ) (25.7 ) (10.3 ) (16.5 ) 10.9 4.9 Total Revenues $ 1,595.3 $ 776.1 $ 2,967.5 $ 2,370.7 $ 3,063.4 $ 1,547.3 $ 1,821.9 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $134 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $646 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $70 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. Year Ended December 31, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 3,751.8 $ 2,189.2 $ — $ — $ — $ — $ 5,941.0 Commercial Revenues 2,206.4 1,273.4 — — — — 3,479.8 Industrial Revenues 2,190.2 494.5 — — — — 2,684.7 Other Retail Revenues 183.1 39.2 — — — — 222.3 Total Retail Revenues 8,331.5 3,996.3 — — — — 12,327.8 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 899.8 — — 544.4 — (226.0 ) 1,218.2 Transmission Revenues (b) 282.2 372.1 849.3 — — (737.1 ) 766.5 Marketing, Competitive Retail and Renewable Revenues — — — 1,353.0 — — 1,353.0 Total Wholesale and Competitive Retail Revenues 1,182.0 372.1 849.3 1,897.4 — (963.1 ) 3,337.7 Other Revenues from Contracts with Customers (c) 158.4 204.6 15.2 20.6 86.2 (32.0 ) 453.0 Total Revenues from Contracts with Customers 9,671.9 4,573.0 864.5 1,918.0 86.2 (995.1 ) 16,118.5 Other Revenues: Alternative Revenues (c) (15.9 ) (22.2 ) (60.4 ) — — 52.7 (45.8 ) Other Revenues (c) (10.5 ) 102.3 — 22.3 8.9 — 123.0 Total Other Revenues (26.4 ) 80.1 (60.4 ) 22.3 8.9 52.7 77.2 Total Revenues $ 9,645.5 $ 4,653.1 $ 804.1 $ 1,940.3 $ 95.1 $ (942.4 ) $ 16,195.7 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $121 million . The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $643 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations	Company 2019 2020-2021 2022-2023 After 2024 Total (in millions) AEP $ 920.7 $ 173.7 $ 162.5 $ 266.3 $ 1,523.2 AEP Texas 332.8 — — — 332.8 AEPTCo 893.6 — — — 893.6 APCo 144.8 32.2 23.2 — 200.2 I&M 25.6 2.9 2.9 — 31.4 OPCo 65.4 — — — 65.4 PSO 17.3 — — — 17.3 SWEPCo 35.2 — — — 35.2
Affiliated Accounts Receivable Contracts with Customers	Company December 31, 2018 January 1, 2018 (in millions) AEPTCo $ 58.6 $ 47.1 APCo 52.5 35.6 I&M 35.3 15.1 OPCo 46.1 26.1 PSO 12.4 6.1 SWEPCo 16.3 11.0

Unaudited Quarterly Financial_2

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Quarterly Financial Information	Quarterly Periods Ended: AEP AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2018 Total Revenues $ 4,048.3 $ 371.6 $ 191.7 $ 820.4 $ 576.8 $ 790.9 $ 336.8 $ 419.4 Operating Income 706.0 81.8 111.1 193.0 97.4 117.3 3.9 41.6 Net Income (Loss) 456.7 46.8 84.1 125.5 64.2 79.6 (7.2 ) 13.4 Earnings Attributable to Common Shareholders 454.4 NA NA NA NA NA NA 11.8 June 30, 2018 Total Revenues $ 4,013.2 $ 388.3 $ 200.1 $ 667.0 $ 589.7 $ 748.8 $ 398.3 $ 457.1 Operating Income 757.0 86.2 110.5 132.6 117.4 104.4 57.2 70.5 Net Income 530.1 46.5 82.0 77.4 94.7 68.8 36.6 38.7 Earnings Attributable to Common Shareholders 528.4 NA NA NA NA NA NA 37.6 September 30, 2018 Total Revenues $ 4,333.1 $ 433.4 $ 194.4 $ 762.0 $ 629.7 $ 778.3 $ 481.4 $ 535.3 Operating Income 668.6 94.0 97.0 49.8 110.2 79.9 78.5 127.1 Net Income 579.7 57.8 78.1 87.1 72.7 88.7 60.4 89.6 Earnings Attributable to Common Shareholders 577.6 NA NA NA NA NA NA 88.2 December 31, 2018 Total Revenues $ 3,801.1 $ 402.0 $ 189.9 $ 718.1 $ 574.5 $ 745.4 $ 330.8 $ 410.1 Operating Income 551.1 84.3 91.5 108.1 52.2 118.2 2.9 38.5 Net Income (Loss) 364.8 60.2 71.7 77.8 29.7 88.4 (6.6 ) 10.5 Earnings Attributable to Common Shareholders 363.4 NA NA NA NA NA NA 9.6 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 (b) 1,085.7 82.3 90.4 218.9 117.2 149.6 19.9 52.8 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 (b) 733.3 108.8 165.4 126.1 33.6 118.5 45.3 74.1 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 $ 165.6 $ 719.3 $ 557.7 $ 742.0 $ 442.8 $ 517.6 Operating Income (b) 975.1 128.8 93.6 171.7 113.6 153.4 85.9 136.0 Net Income 556.7 64.3 58.6 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 $ 159.2 $ 746.8 $ 535.7 $ 731.9 $ 335.6 $ 436.3 Operating Income (b) 730.9 96.2 83.5 173.6 82.8 144.2 20.4 41.1 Net Income 401.8 163.9 47.7 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. (a) The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1. (b) Amounts reflect the adoption of ASU 2017-07 “Compensation - Retirement Benefits”. See Note 2 - New Accounting Pronouncements for additional information. 2018 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders (in millions) $ 454.4 $ 528.4 $ 577.6 $ 363.4 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 0.92 1.07 1.17 0.74 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 0.92 1.07 1.17 0.74 2017 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders (in millions) $ 592.2 $ 375.0 $ 544.7 $ 400.7 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.20 0.76 1.11 0.81 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.20 0.76 1.10 0.81 (a) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies (Details) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended						63 Months Ended	90 Months Ended
	Dec. 31, 2018USD ($)$ / shares		Sep. 30, 2018USD ($)$ / shares		Jun. 30, 2018USD ($)$ / shares		Mar. 31, 2018USD ($)$ / shares		Dec. 31, 2017USD ($)$ / shares		Sep. 30, 2017USD ($)$ / shares		Jun. 30, 2017USD ($)$ / shares		Mar. 31, 2017USD ($)$ / shares		Dec. 31, 2018USD ($)$ / sharesshares		Dec. 31, 2017USD ($)$ / sharesshares		Dec. 31, 2016USD ($)$ / sharesshares		Mar. 31, 2018	Jun. 30, 2018	Dec. 31, 2015USD ($)
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period							$ 214.6										$ 214.6
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	1,965		$ 1,709.1		$ 1,688.5
Amortization of Certain Securitized Assets																	287.9		275.9		254.6
Amortization of Regulatory Assets and Liabilities																	33.7		12.2		19.2
Utilities Operating Expense, Depreciation and Amortization																	2,286.6		1,997.2		1,962.3
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	939.3		858.3		848.5
Income Taxes Paid, Net																	(24.7)		(1.1)		29.5
Construction in Progress Expenditures Incurred but Not yet Paid																	1,120.4		1,330.8		858
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	55.6		60.7		86.1
Construction Expenditures Included in Current Liabilities as of December 31,																	1,120.4		1,330.8		858
Construction Expenditures Included in Noncurrent Liabilities as of December 31,																	0		71.8		0
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,																	4		0		2.1
Noncash Contribution of Assets by Noncontrolling Interest																	84		0		0
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage																	2.2		2.6		0.7
Restricted Cash	$ 210								$ 198								210		198
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Including Disposal Group and Discontinued Operations	$ 444.1								$ 412.6								444.1		412.6		403.5				$ 426.9
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest																	1,931.3		1,928.9		620.5
Net Income (Loss) Attributable to Noncontrolling Interests																	7.5		16.3		7.1
Net Income (Loss) from Continuing Operations Available to Common Shareholders, Basic																	$ 1,923.8		$ 1,912.6		$ 613.4
Weighted Average Number of Basic AEP Common Shares Outstanding | shares																	492,774,600		491,814,651		491,495,458
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares	$ 0.74	[1]	$ 1.17	[1]	$ 1.07	[1]	$ 0.92	[1]	$ 0.81	[1]	$ 1.11	[1]	$ 0.76	[1]	$ 1.20	[1]	$ 3.90		$ 3.89		$ 1.25
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding | shares																	493,758,277		492,611,067		491,662,007
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares	$ 0.74	[1]	$ 1.17	[1]	$ 1.07	[1]	$ 0.92	[1]	$ 0.81	[1]	$ 1.10	[1]	$ 0.76	[1]	$ 1.20	[1]	$ 3.90		$ 3.88		$ 1.25
Revenues
TOTAL REVENUES	$ 3,801.1		$ 4,333.1		$ 4,013.2		$ 4,048.3		$ 3,810.4		$ 4,104.7		$ 3,576.5		$ 3,933.3		$ 16,195.7		$ 15,424.9		$ 16,380.1
Expenses
Depreciation and Amortization																	2,286.6		1,997.2		1,962.3
TOTAL EXPENSES																	13,513		11,899.9		15,216.2
OPERATING INCOME (LOSS)	551.1		668.6		757		706		730.9	[2]	975.1	[2]	733.3	[2]	1,085.7	[2]	2,682.7		3,525		1,163.9
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	132.5		93.7		113.2
Interest Expense																	(984.4)		(895)		(877.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	1,973.5		2,816.2		475.6
Income Tax Expense (Benefit)																	115.3		969.7		(73.7)
NET INCOME (LOSS)	364.8		579.7		530.1		456.7		401.8		556.7		376.2		594.2		1,931.3		1,928.9		618
Accounts Receivable:
Customers	699								643.9								699		643.9
Total Accounts Receivable	1,926.5								1,891								1,926.5		1,891
TOTAL CURRENT ASSETS	4,113.9								4,253.1								4,113.9		4,253.1
Property, Plant and Equipment
Transmission	21,531								18,972.5								21,531		18,972.5
Other Property, Plant and Equipment	4,265								3,706.3								4,265		3,706.3
Construction Work in Progress	4,393.9								4,120.7								4,393.9		4,120.7
Total Property, Plant and Equipment	73,085.2								67,428.5								73,085.2		67,428.5
Accumulated Depreciation and Amortization	17,986.1								17,167								17,986.1		17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	55,099.1								50,261.5								55,099.1		50,261.5
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	9,589.8								10,214.5								9,589.8		10,214.5
TOTAL ASSETS	68,802.8								64,729.1								68,802.8		64,729.1		63,467.7
Current Liabilities
Accounts Payable	1,874.3								2,065.3								1,874.3		2,065.3
Accrued Taxes	1,218								1,115.5								1,218		1,115.5
TOTAL CURRENT LIABILITIES	8,648.8								8,271.3								8,648.8		8,271.3
Liabilities, Noncurrent
Deferred Income Taxes	7,086.5								6,813.9								7,086.5		6,813.9
Regulatory Liabilities and Deferred Investment Tax Credits	8,540.3								8,422.3								8,540.3		8,422.3
TOTAL NONCURRENT LIABILITIES	40,985.8								38,132.3								40,985.8		38,132.3
TOTAL LIABILITIES	49,634.6								46,403.6								49,634.6		46,403.6
Equity [Abstract]
Retained Earnings	9,325.3								8,626.7								9,325.3		8,626.7
TOTAL LIABILITIES AND EQUITY	68,802.8								64,729.1								68,802.8		64,729.1
Operating Activites
NET INCOME (LOSS)	364.8		579.7		530.1		456.7		401.8		556.7		376.2		594.2		1,931.3		1,928.9		618
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	2,286.6		1,997.2		1,962.3
Deferred Income Taxes																	104.3		901.5		(50)
Allowance for Equity Funds Used During Construction																	(132.5)		(93.7)		(113.2)
Amortization of Deferred Property Taxes																	(59.1)		(29.5)		(19)
Change in Other Noncurrent Assets																	119.8		(423.9)		(454.6)
Increase (Decrease) in Other Noncurrent Liabilities																	129		181.7		15.4
Accounts Receivable, Net																	145.9		28.5		(226.6)
Accounts Payable																	36.6		(58)		164.9
Accrued Taxes, Net																	153.2		91.9		42.8
Net Cash Provided by (Used in) Financing Activities
Cash and Cash Equivalents at Beginning of Period							214.6										214.6
Cash and Cash Equivalents at End of Period	$ 234.1								214.6								234.1		214.6
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	4,945.7		3,854.1		2,594.9
Repayments of Long-term Debt																	$ 2,782		3,087.9		1,794.9
Number of Equity Method Investments	2																2
Equity Method Investment	$ 846.2								812.3								$ 846.2		812.3
Income (Loss) from Equity Method Investment																	$ 73.1		$ 82.4		$ 71.2
Antidilutive Shares Outstanding | shares																	0		0		0
Net Income (Loss)	364.8		579.7		530.1		456.7		401.8		556.7		376.2		594.2		$ 1,931.3		$ 1,928.9		$ 618
Retained Earnings	$ 9,325.3								8,626.7								$ 9,325.3		8,626.7
ETT [Member]
Organization and Summary of Significant Accounting Policies (Textuals)
Equity Method Investment, Ownership Percentage	50.00%																50.00%
Equity Method Investment	$ 666								664								$ 666		664
Income (Loss) from Equity Method Investment																	$ 62		82
ETT [Member] | Berkshire Hathaway [Member]
Organization and Summary of Significant Accounting Policies (Textuals)
Equity Method Investment, Ownership Percentage	50.00%																50.00%
ETT [Member] | AEP Transmission Holdco [Member]
Organization and Summary of Significant Accounting Policies (Textuals)
Equity Method Investment, Ownership Percentage	49.50%																49.50%
ETT [Member] | AEP Transmission Partner [Member]
Organization and Summary of Significant Accounting Policies (Textuals)
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
Cash and Cash Equivalents at Beginning of Period							2										$ 2
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	262.2		221.1		204
Amortization of Certain Securitized Assets																	240		231.4		210.3
Amortization of Regulatory Assets and Liabilities																	(2.6)		(2.4)		(0.4)
Utilities Operating Expense, Depreciation and Amortization																	499.6		450.1		413.9
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	145.9		134.6		145.6
Income Taxes Paid, Net																	7.9		(28.3)		38.2
Construction in Progress Expenditures Incurred but Not yet Paid																	243.1		325.7		100.1
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	10.6		8.2		7.1
Construction Expenditures Included in Current Liabilities as of December 31,																	243.1		325.7		100.1
Restricted Cash	$ 156.7								155.2								156.7		155.2
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	159.8								157.2								159.8		157.2		$ 146.9				208.4
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Including Disposal Group and Discontinued Operations	159.8								157.2								$ 159.8		$ 157.2
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest																	$ 211.3		$ 310.5		$ 195.4
Revenues
TOTAL REVENUES	402		433.4		388.3		371.6		374.1		431.2		389.5		343.6		1,595.3		1,538.4		1,461.4
Expenses
Depreciation and Amortization																	499.6		450.1		413.9
TOTAL EXPENSES																	1,249		1,122.3		1,085.1
OPERATING INCOME (LOSS)	84.3		94		86.2		81.8		96.2	[2]	128.8	[2]	108.8	[2]	82.3	[2]	346.3		416.1		376.3
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	20		6.8		9.2
Interest Expense																	(147.3)		(142.3)		(144.4)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	232.1		287.1		255.3
Income Tax Expense (Benefit)																	20.8		(23.4)		59.9
NET INCOME (LOSS)	60.2		57.8		46.5		46.8		163.9		64.3		49		33.3		211.3		310.5		146.6
Accounts Receivable:
Customers	110.9								105.3								110.9		105.3
Total Accounts Receivable	196.9								194								196.9		194
Accrued Tax Benefits	44.9								41								44.9		41
TOTAL CURRENT ASSETS	476.5								563.8								476.5		563.8
Property, Plant and Equipment
Transmission	3,683.6								3,053.6								3,683.6		3,053.6
Other Property, Plant and Equipment	727.9								461								727.9		461
Construction Work in Progress	836.2								835.7								836.2		835.7
Total Property, Plant and Equipment	9,643								8,419.6								9,643		8,419.6
Accumulated Depreciation and Amortization	1,651.2								1,594.5								1,651.2		1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	7,991.8								6,825.1								7,991.8		6,825.1
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	1,135.4								1,384.7								1,135.4		1,384.7
TOTAL ASSETS	9,603.7								8,773.6								9,603.7		8,773.6
Current Liabilities
Accounts Payable	276.5								379.4								276.5		379.4
Affiliated Companies	30.3								30.2								30.3		30.2
Accrued Taxes	75.5								77.2								75.5		77.2
TOTAL CURRENT LIABILITIES	1,259.5								871.5								1,259.5		871.5
Liabilities, Noncurrent
Deferred Income Taxes	913.1								913.1								913.1		913.1
Regulatory Liabilities and Deferred Investment Tax Credits	1,344.3								1,320.5								1,344.3		1,320.5
TOTAL NONCURRENT LIABILITIES	5,763.7								5,732.2								5,763.7		5,732.2
TOTAL LIABILITIES	7,023.2								6,603.7								7,023.2		6,603.7
Equity [Abstract]
Retained Earnings	1,337.7								1,124.6								1,337.7		1,124.6
TOTAL LIABILITIES AND EQUITY	9,603.7								8,773.6								9,603.7		8,773.6
Operating Activites
NET INCOME (LOSS)	60.2		57.8		46.5		46.8		163.9		64.3		49		33.3		211.3		310.5		146.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	499.6		450.1		413.9
Deferred Income Taxes																	(16.5)		63.3		29.5
Allowance for Equity Funds Used During Construction																	(20)		(6.8)		(9.2)
Change in Other Noncurrent Assets																	(35.4)		(49.4)		(44.1)
Increase (Decrease) in Other Noncurrent Liabilities																	44.9		8.8		(10.3)
Accounts Receivable, Net																	(2.9)		(23.5)		(22.6)
Accounts Payable																	(20.3)		30.8		(3)
Accrued Taxes, Net																	(5.6)		(31.3)		(22.6)
Net Cash Provided by (Used in) Financing Activities
Cash and Cash Equivalents at Beginning of Period							2										2
Cash and Cash Equivalents at End of Period	3.1								2								3.1		2
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	494		749.6		199.2
Repayments of Long-term Debt																	266.1		323.1		428.7
Net Income (Loss)	60.2		57.8		46.5		46.8		163.9		64.3		49		33.3		211.3		310.5		146.6
Retained Earnings	$ 1,337.7								1,124.6								$ 1,337.7		1,124.6
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] | 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
Cash and Cash Equivalents at Beginning of Period							0								0		$ 0		0		0
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	133.9		95.7	[3]	65.9
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	0		0		0
Utilities Operating Expense, Depreciation and Amortization																	133.9		95.7	[3],[4]	65.9
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	80.2		62.4		42
Income Taxes Paid, Net																	(30.7)		(107.3)		(235.1)
Construction in Progress Expenditures Incurred but Not yet Paid																	345		485		298.3
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	0		0.2		0
Construction Expenditures Included in Current Liabilities as of December 31,																	$ 345		$ 485		$ 298.3
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Revenues
TOTAL REVENUES	$ 189.9	[5]	194.4	[5]	200.1	[5]	191.7	[5]	159.2		165.6		229.4		152.7		$ 776.1		$ 706.9	[4]	$ 478
Expenses
Depreciation and Amortization																	133.9		95.7	[3],[4]	65.9
TOTAL EXPENSES																	366		274		197.9
OPERATING INCOME (LOSS)	91.5	[5]	97	[5]	110.5	[5]	111.1	[5]	83.5	[2]	93.6	[2]	165.4	[2]	90.4	[2]	410.1		432.9		280.1
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	70.6		49	[4],[6]	52.3
Interest Expense																	(83.2)		(70.2)	[4]	(46)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	400		412.9		286.8
Income Tax Expense (Benefit)																	84.1		142.2	[4],[7]	94.1
NET INCOME (LOSS)	71.7	[5]	78.1	[5]	82	[5]	84.1	[5]	47.7		58.6		107.4		57		315.9		270.7	[4],[7]	192.7
Accounts Receivable:
Customers	11.8								15								11.8		15
Total Accounts Receivable	72.8								109.5								72.8		109.5
Accrued Tax Benefits	33.4								49.4								33.4		49.4
TOTAL CURRENT ASSETS	225.5								326.4								225.5		326.4
Property, Plant and Equipment
Transmission	6,515.8								5,319.7								6,515.8		5,319.7
Other Property, Plant and Equipment	174								126.8								174		126.8
Construction Work in Progress	1,578.3								1,324								1,578.3		1,324
Total Property, Plant and Equipment	8,268.1								6,770.5	[4]							8,268.1		6,770.5	[4]
Accumulated Depreciation and Amortization	271.9								152.6	[4]							271.9		152.6	[4]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	7,996.2								6,617.9	[4],[8]							7,996.2		6,617.9	[4],[8]
Other Noncurrent Assets
Deferred Property Taxes	157.9								125								157.9		125
TOTAL OTHER NONCURRENT ASSETS	172.4								137.8								172.4		137.8
TOTAL ASSETS	8,394.1								7,082.1	[4]							8,394.1		7,082.1	[4]	5,349.8
Current Liabilities
Accounts Payable	347.2								484.5								347.2		484.5
Affiliated Companies	56								66.1								56		66.1
Accrued Taxes	288.9								231.5								288.9		231.5
TOTAL CURRENT LIABILITIES	842.2								866.9								842.2		866.9
Liabilities, Noncurrent
Deferred Income Taxes	704.4								600.4								704.4		600.4
Regulatory Liabilities and Deferred Investment Tax Credits	521.3								493.8								521.3		493.8
TOTAL NONCURRENT LIABILITIES	3,982.1								3,625.3								3,982.1		3,625.3
TOTAL LIABILITIES	4,824.3								4,492.2								4,824.3		4,492.2
Equity [Abstract]
Retained Earnings	1,089.2								773.3								1,089.2		773.3
TOTAL MEMBER'S EQUITY	3,569.8								2,589.9								3,569.8		2,589.9		1,957.6				1,552.9
TOTAL LIABILITIES AND EQUITY	8,394.1								7,082.1								8,394.1		7,082.1
Operating Activites
NET INCOME (LOSS)	71.7	[5]	78.1	[5]	82	[5]	84.1	[5]	47.7		58.6		107.4		57		315.9		270.7	[4],[7]	192.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	133.9		95.7	[3],[4]	65.9
Deferred Income Taxes																	98.9		271.5		223.1
Allowance for Equity Funds Used During Construction																	(70.6)		(49)	[4],[6]	(52.3)
Amortization of Deferred Property Taxes																	(32.9)		(22.8)		(15.3)
Change in Other Noncurrent Assets																	14.6		11		(2.8)
Increase (Decrease) in Other Noncurrent Liabilities																	17.4		27.5		4.4
Accounts Receivable, Net																	36.7		(30.4)		(22.6)
Accounts Payable																	(7.5)		23		14.3
Accrued Taxes, Net																	73.4		16.3		143.8
Net Cash Flows from (Used for) Operating Activities																	548.6		604.8		548.9
Investing Activities
Net Cash Flows from (Used for) Investing Activities																	(1,513.3)		(1,595.6)		(1,135)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																	964.7		990.8		586.1
Net Increase (Decrease) in Cash and Cash Equivalents																	0		0		0
Cash and Cash Equivalents at Beginning of Period							0								0		0		0		0
Cash and Cash Equivalents at End of Period	0								0								0		0		0
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	321		617.6		686.9
Repayments of Long-term Debt																	50		0		300
Net Income (Loss)	71.7	[5]	78.1	[5]	82	[5]	84.1	[5]	47.7		58.6		107.4		57		315.9		270.7	[4],[7]	192.7
Retained Earnings	1,089.2								773.3								1,089.2		773.3
Appalachian Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period							2.9										2.9
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	428.1		407.6		387.6
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	0.3		0.3		0.9
Utilities Operating Expense, Depreciation and Amortization																	428.4		407.9		388.5
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	182		183.6		181.8
Income Taxes Paid, Net																	(13)		31.2		22.1
Construction in Progress Expenditures Incurred but Not yet Paid																	134.4		126.3		151.6
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	5.5		3.5		6.1
Construction Expenditures Included in Current Liabilities as of December 31,																	134.4		126.3		151.6
Restricted Cash	25.6								16.3								25.6		16.3
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	29.8								19.2								$ 29.8		$ 19.2		$ 18.5				17.6
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Revenues
TOTAL REVENUES	718.1		762		667		820.4		746.8		719.3		675.3		792.8		$ 2,967.5		$ 2,934.2		$ 3,001.2
Expenses
Depreciation and Amortization																	428.4		407.9		388.5
TOTAL EXPENSES																	2,484		2,243.9		2,262.9
OPERATING INCOME (LOSS)	108.1		49.8		132.6		193		173.6	[2]	171.7	[2]	126.1	[2]	218.9	[2]	483.5		690.3		738.3
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	13.2		9.2		11.7
Interest Expense																	(194.8)		(190.9)		(188.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	322.9		516.6		568.2
Income Tax Expense (Benefit)																	(44.9)		185.3		199.1
NET INCOME (LOSS)	77.8		87.1		77.4		125.5		82.6		86		52.1		110.6		367.8		331.3		369.1
Accounts Receivable:
Customers	146.5								123.1								146.5		123.1
Total Accounts Receivable	283.4								263.9								283.4		263.9
TOTAL CURRENT ASSETS	698.7								636.2								698.7		636.2
Property, Plant and Equipment
Transmission	3,317.7								3,019.9								3,317.7		3,019.9
Other Property, Plant and Equipment	485.8								427.9								485.8		427.9
Construction Work in Progress	490.2								483								490.2		483
Total Property, Plant and Equipment	14,792.7								14,141.5								14,792.7		14,141.5
Accumulated Depreciation and Amortization	4,124.4								3,896.4								4,124.4		3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	10,668.3								10,245.1								10,668.3		10,245.1
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	923.5								1,047.3								923.5		1,047.3
TOTAL ASSETS	12,290.5								11,928.6								12,290.5		11,928.6
Current Liabilities
Accounts Payable	263.8								264.9								263.8		264.9
Affiliated Companies	84								92.7								84		92.7
Accrued Taxes	89.3								94.5								89.3		94.5
TOTAL CURRENT LIABILITIES	1,354								1,124.2								1,354		1,124.2
Liabilities, Noncurrent
Deferred Income Taxes	1,625.8								1,565.7								1,625.8		1,565.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,449.7								1,454.9								1,449.7		1,454.9
TOTAL NONCURRENT LIABILITIES	6,930.4								6,999.9								6,930.4		6,999.9
TOTAL LIABILITIES	8,284.4								8,124.1								8,284.4		8,124.1
Equity [Abstract]
Retained Earnings	1,922								1,714.1								1,922		1,714.1
TOTAL LIABILITIES AND EQUITY	12,290.5								11,928.6								12,290.5		11,928.6
Operating Activites
NET INCOME (LOSS)	77.8		87.1		77.4		125.5		82.6		86		52.1		110.6		367.8		331.3		369.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	428.4		407.9		388.5
Deferred Income Taxes																	(16.8)		171.5		130.7
Allowance for Equity Funds Used During Construction																	(13.2)		(9.2)		(11.7)
Change in Other Noncurrent Assets																	59.4		12.8		3.4
Increase (Decrease) in Other Noncurrent Liabilities																	(4.8)		11.9		(26.1)
Accounts Receivable, Net																	33.6		(28)		(48)
Accounts Payable																	(13.3)		37.5		19.5
Accrued Taxes, Net																	(13.2)		(12.7)		53.7
Net Cash Flows from (Used for) Operating Activities																	846.6		880		894.7
Investing Activities
Net Cash Flows from (Used for) Investing Activities																	(769.4)		(802.3)		(631.9)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																	(66.6)		(77)		(261.9)
Cash and Cash Equivalents at Beginning of Period							2.9										2.9
Cash and Cash Equivalents at End of Period	4.2								2.9								4.2		2.9
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	203.2		320.9		314
Repayments of Long-term Debt																	124		377.9		213.6
Net Income (Loss)	77.8		87.1		77.4		125.5		82.6		86		52.1		110.6		367.8		331.3		369.1
Retained Earnings	$ 1,922								1,714.1								$ 1,922		1,714.1
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
Cash and Cash Equivalents at Beginning of Period							1.3								1.2		$ 1.3		1.2		1.1
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)																	63.4		62.6		62.1
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	278.9		203.1		183.9
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	14.2		7.8		7.8
Utilities Operating Expense, Depreciation and Amortization																	293.1		210.9		191.7
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	116.9		94.8		83.3
Income Taxes Paid, Net																	32.6		(89.9)		(39.5)
Construction in Progress Expenditures Incurred but Not yet Paid																	93		88.5		106.2
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	5.8		7.1		18.2
Construction Expenditures Included in Current Liabilities as of December 31,																	93		88.5		106.2
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,																	4		0		2.1
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage																	$ 2.2		$ 2.6		$ 0.7
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Revenues
TOTAL REVENUES	$ 574.5		629.7		589.7		576.8		535.7		557.7		467.3		560.5		$ 2,370.7		$ 2,121.2		$ 2,167.6
Expenses
Depreciation and Amortization																	293.1		210.9		191.7
TOTAL EXPENSES																	1,993.5		1,774		1,793.3
OPERATING INCOME (LOSS)	52.2		110.2		117.4		97.4		82.8	[2]	113.6	[2]	33.6	[2]	117.2	[2]	377.2		347.2		374.3
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	11.9		11.1		15.3
Interest Expense																	(124.1)		(110.8)		(100.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	290.4		268.1		307.4
Income Tax Expense (Benefit)																	29.1		81.4		67.5
NET INCOME (LOSS)	29.7		72.7		94.7		64.2		42.9		64.9		10.5		68.4		261.3		186.7		239.9
Accounts Receivable:
Customers	63.1								56.4								63.1		56.4
Total Accounts Receivable	143								115.6								143		115.6
Accrued Tax Benefits	26.6								58.4								26.6		58.4
TOTAL CURRENT ASSETS	430.4								434								430.4		434
Property, Plant and Equipment
Transmission	1,576.8								1,504								1,576.8		1,504
Other Property, Plant and Equipment	583.8								595.2								583.8		595.2
Construction Work in Progress	465.3								460.2								465.3		460.2
Total Property, Plant and Equipment	9,762.8								9,074.6								9,762.8		9,074.6
Accumulated Depreciation and Amortization	3,151.6								3,024.2								3,151.6		3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,611.2								6,050.4								6,611.2		6,050.4
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	3,181								3,287.6								3,181		3,287.6
TOTAL ASSETS	10,222.6								9,772								10,222.6		9,772
Current Liabilities
Accounts Payable	174.7								154.5								174.7		154.5
Affiliated Companies	70.2								98.3								70.2		98.3
Accrued Taxes	90.7								81.3								90.7		81.3
TOTAL CURRENT LIABILITIES	698.1								1,211.3								698.1		1,211.3
Liabilities, Noncurrent
Deferred Income Taxes	948								953.8								948		953.8
Regulatory Liabilities and Deferred Investment Tax Credits	1,574.5								1,708.7								1,574.5		1,708.7
TOTAL NONCURRENT LIABILITIES	7,171.7								6,343.1								7,171.7		6,343.1
TOTAL LIABILITIES	7,869.8								7,554.4								7,869.8		7,554.4
Equity [Abstract]
Retained Earnings	1,329.1								1,192.2								1,329.1		1,192.2
TOTAL LIABILITIES AND EQUITY	10,222.6								9,772								10,222.6		9,772
Operating Activites
NET INCOME (LOSS)	29.7		72.7		94.7		64.2		42.9		64.9		10.5		68.4		261.3		186.7		239.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	293.1		210.9		191.7
Deferred Income Taxes																	(42.9)		200.7		105.1
Allowance for Equity Funds Used During Construction																	(11.9)		(11.1)		(15.3)
Change in Other Noncurrent Assets																	(32.6)		(88.4)		(56.4)
Increase (Decrease) in Other Noncurrent Liabilities																	72.1		37.4		58.2
Accounts Receivable, Net																	4.8		(1.1)		0.5
Accounts Payable																	(14.1)		17.6		11.6
Accrued Taxes, Net																	41.2		(16.6)		6
Net Cash Flows from (Used for) Operating Activities																	725.7		661.3		529.7
Investing Activities
Net Cash Flows from (Used for) Investing Activities																	(654.8)		(790.9)		(760.1)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																	(69.8)		129.7		230.5
Net Increase (Decrease) in Cash and Cash Equivalents																	1.1		0.1		0.1
Cash and Cash Equivalents at Beginning of Period							1.3								1.2		1.3		1.2		1.1
Cash and Cash Equivalents at End of Period	2.4								1.3								2.4		1.3		1.2
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	1,168.1		530.1		569.4
Repayments of Long-term Debt																	884.9		260.7		100.2
Net Income (Loss)	29.7		72.7		94.7		64.2		42.9		64.9		10.5		68.4		261.3		186.7		239.9
Retained Earnings	$ 1,329.1								1,192.2								$ 1,329.1		1,192.2
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] | 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
Cash and Cash Equivalents at Beginning of Period							3.1										$ 3.1
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	232.6		200.9		202.3
Amortization of Certain Securitized Assets																	47.9		44.4		44.3
Amortization of Regulatory Assets and Liabilities																	(20.8)		(19.4)		(8)
Utilities Operating Expense, Depreciation and Amortization																	259.7		225.9		238.6
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	97.1		100		109.9
Income Taxes Paid, Net																	51.3		48.5		220.4
Construction in Progress Expenditures Incurred but Not yet Paid																	98.2		87.8		44.6
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	4.4		4.5		3.4
Construction Expenditures Included in Current Liabilities as of December 31,																	98.2		87.8		44.6
Restricted Cash	$ 27.6								26.6								27.6		26.6
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	32.5								29.7								$ 32.5		$ 29.7		$ 30.3				$ 30.8
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Revenues
TOTAL REVENUES	745.4		778.3		748.8		790.9		731.9		742		663.9		746.1		$ 3,063.4		$ 2,883.9		$ 2,953.9
Expenses
Depreciation and Amortization																	259.7		225.9		238.6
TOTAL EXPENSES																	2,643.6		2,318.2		2,449.8
OPERATING INCOME (LOSS)	118.2		79.9		104.4		117.3		144.2	[2]	153.4	[2]	118.5	[2]	149.6	[2]	419.8		565.7		504.1
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	9.8		6.4		6
Interest Expense																	(100.7)		(101.9)		(112.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	349.5		483.2		426
Income Tax Expense (Benefit)																	24		159.3		143.8
NET INCOME (LOSS)	88.4		88.7		68.8		79.6		92.8		82.6		62.3		86.2		325.5		323.9		282.2
Accounts Receivable:
Customers	111.1								67.8								111.1		67.8
Total Accounts Receivable	202.6								169								202.6		169
TOTAL CURRENT ASSETS	319.6								397.9								319.6		397.9
Property, Plant and Equipment
Transmission	2,544.3								2,419.2								2,544.3		2,419.2
Other Property, Plant and Equipment	574.8								495.9								574.8		495.9
Construction Work in Progress	432.1								410.1								432.1		410.1
Total Property, Plant and Equipment	8,493.5								7,951.6								8,493.5		7,951.6
Accumulated Depreciation and Amortization	2,218.6								2,184.8								2,218.6		2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,274.9								5,766.8								6,274.9		5,766.8
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	841.4								1,097								841.4		1,097
TOTAL ASSETS	7,435.9								7,261.7								7,435.9		7,261.7
Current Liabilities
Accounts Payable	211.9								205.8								211.9		205.8
Affiliated Companies	102.9								118.2								102.9		118.2
Accrued Taxes	537.8								512.5								537.8		512.5
TOTAL CURRENT LIABILITIES	1,347.7								1,593.8								1,347.7		1,593.8
Liabilities, Noncurrent
Deferred Income Taxes	763.3								762.9								763.3		762.9
Regulatory Liabilities and Deferred Investment Tax Credits	1,221.2								1,100.2								1,221.2		1,100.2
TOTAL NONCURRENT LIABILITIES	3,790.8								3,357.6								3,790.8		3,357.6
TOTAL LIABILITIES	5,138.5								4,951.4								5,138.5		4,951.4
Equity [Abstract]
Retained Earnings	1,136.4								1,148.4								1,136.4		1,148.4
TOTAL LIABILITIES AND EQUITY	7,435.9								7,261.7								7,435.9		7,261.7
Operating Activites
NET INCOME (LOSS)	88.4		88.7		68.8		79.6		92.8		82.6		62.3		86.2		325.5		323.9		282.2
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	259.7		225.9		238.6
Deferred Income Taxes																	(36.2)		147.9		(39.2)
Allowance for Equity Funds Used During Construction																	(9.8)		(6.4)		(6)
Amortization of Deferred Property Taxes																	(12.5)		(17.9)		(9.8)
Change in Other Noncurrent Assets																	(9.8)		(51.1)		(44.6)
Increase (Decrease) in Other Noncurrent Liabilities																	53.8		15.8		31
Accounts Receivable, Net																	43.1		(30.1)		(26.6)
Accounts Payable																	(13.8)		11.6		13.7
Accrued Taxes, Net																	26.8		(9.4)		(6)
Net Cash Flows from (Used for) Operating Activities																	1,028.7		622.2		646.3
Investing Activities
Net Cash Flows from (Used for) Investing Activities																	(707.5)		(530.9)		(97.3)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																	(318.4)		(91.9)		(549.5)
Cash and Cash Equivalents at Beginning of Period							3.1										3.1
Cash and Cash Equivalents at End of Period	4.9								3.1								4.9		3.1
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	392.8		0		0
Repayments of Long-term Debt																	397.1		46.4		395.9
Net Income (Loss)	88.4		88.7		68.8		79.6		92.8		82.6		62.3		86.2		325.5		323.9		282.2
Retained Earnings	$ 1,136.4								1,148.4								$ 1,136.4		1,148.4
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] | 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
Cash and Cash Equivalents at Beginning of Period							1.6								1.5		$ 1.6		1.5		1.4
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	155.5		131.4		122.6
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	8.5		(1)		7.6
Utilities Operating Expense, Depreciation and Amortization																	164		130.4		130.2
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	62		61.5		60.1
Income Taxes Paid, Net																	17.9		(72.6)		(37.7)
Construction in Progress Expenditures Incurred but Not yet Paid																	33.2		23.1		33.6
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	4.3		2.1		3.1
Construction Expenditures Included in Current Liabilities as of December 31,																	$ 33.2		$ 23.1		$ 33.6
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Revenues
TOTAL REVENUES	$ 330.8		481.4		398.3		336.8		335.6		442.8		344.7		304.1		$ 1,547.3		$ 1,427.2		$ 1,249.8
Expenses
Depreciation and Amortization																	164		130.4		130.2
TOTAL EXPENSES																	1,404.8		1,255.7		1,054.2
OPERATING INCOME (LOSS)	2.9		78.5		57.2		3.9		20.4	[2]	85.9	[2]	45.3	[2]	19.9	[2]	142.5		171.5		195.6
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	0.4		0.5		6.2
Interest Expense																	(63.5)		(53.4)		(51.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	88.2		122.1		154.4
Income Tax Expense (Benefit)																	5		50.1		54.4
NET INCOME (LOSS)	(6.6)		60.4		36.6		(7.2)		0.6		46.2		20.4		4.8		83.2		72		100
Accounts Receivable:
Customers	32.5								32.5								32.5		32.5
Total Accounts Receivable	64.3								69.4								64.3		69.4
Accrued Tax Benefits	14.7								28.1								14.7		28.1
TOTAL CURRENT ASSETS	157.9								205.3								157.9		205.3
Property, Plant and Equipment
Transmission	892.3								858.8								892.3		858.8
Other Property, Plant and Equipment	303.5								287.4								303.5		287.4
Construction Work in Progress	94								111.3								94		111.3
Total Property, Plant and Equipment	5,439.6								5,279.8								5,439.6		5,279.8
Accumulated Depreciation and Amortization	1,472.9								1,393.6								1,472.9		1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	3,966.7								3,886.2								3,966.7		3,886.2
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	407.8								416.8								407.8		416.8
TOTAL ASSETS	4,532.4								4,508.3								4,532.4		4,508.3
Current Liabilities
Accounts Payable	126.9								102.4								126.9		102.4
Affiliated Companies	47.1								48								47.1		48
Accrued Taxes	22.4								22.6								22.4		22.6
TOTAL CURRENT LIABILITIES	821.6								436								821.6		436
Liabilities, Noncurrent
Deferred Income Taxes	607.8								642								607.8		642
Regulatory Liabilities and Deferred Investment Tax Credits	864.7								853.5								864.7		853.5
TOTAL NONCURRENT LIABILITIES	2,462.8								2,857								2,462.8		2,857
TOTAL LIABILITIES	3,284.4								3,293								3,284.4		3,293
Equity [Abstract]
Retained Earnings	724.7								691.5								724.7		691.5
TOTAL LIABILITIES AND EQUITY	4,532.4								4,508.3								4,532.4		4,508.3
Operating Activites
NET INCOME (LOSS)	(6.6)		60.4		36.6		(7.2)		0.6		46.2		20.4		4.8		83.2		72		100
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	164		130.4		130.2
Deferred Income Taxes																	(31.1)		124.7		82.5
Allowance for Equity Funds Used During Construction																	(0.4)		(0.5)		(6.2)
Change in Other Noncurrent Assets																	0		(27.2)		(35.9)
Increase (Decrease) in Other Noncurrent Liabilities																	17.6		4.5		(0.1)
Accounts Receivable, Net																	5.1		(10.9)		(9)
Accounts Payable																	17.7		(10.7)		25.7
Accrued Taxes, Net																	13.2		0.8		7.4
Net Cash Flows from (Used for) Operating Activities																	330.5		238.1		217.2
Investing Activities
Net Cash Flows from (Used for) Investing Activities																	(233)		(261.5)		(259.5)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																	(97.1)		23.5		42.4
Net Increase (Decrease) in Cash and Cash Equivalents																	0.4		0.1		0.1
Cash and Cash Equivalents at Beginning of Period							1.6								1.5		1.6		1.5		1.4
Cash and Cash Equivalents at End of Period	2								1.6								2		1.6		1.5
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	0		0		274.2
Repayments of Long-term Debt																	0.5		0.5		275.4
Net Income (Loss)	(6.6)		60.4		36.6		(7.2)		0.6		46.2		20.4		4.8		83.2		72		100
Retained Earnings	$ 724.7								691.5								$ 724.7		691.5
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] | 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
Cash and Cash Equivalents at Beginning of Period							1.6								10.3		$ 1.6		10.3		5.2
Supplemental Income Statement Elements
Depreciation and Amortization of Property, Plant and Equipment																	237		217.2		196.6
Amortization of Certain Securitized Assets																	0		0		0
Amortization of Regulatory Assets and Liabilities																	2.5		0.2		(0.1)
Utilities Operating Expense, Depreciation and Amortization																	239.5		217.4		196.5
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																	125.7		124.4		118
Income Taxes Paid, Net																	18.8		(75.3)		(32)
Construction in Progress Expenditures Incurred but Not yet Paid																	42		71.2		41.8
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																	3.6		3.3		5.9
Construction Expenditures Included in Current Liabilities as of December 31,																	$ 42		$ 71.2		$ 41.8
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	10.00%		10.00%		10.00%
Amounts Attributable to AEP Common Shareholders
Net Income (Loss) Attributable to Noncontrolling Interests																	$ 5		$ 12.8		$ 4.1
Revenues
TOTAL REVENUES	$ 410.1		535.3		457.1		419.4		436.3		517.6		424.7		401.3		1,821.9		1,779.9		1,748
Expenses
Depreciation and Amortization																	239.5		217.4		196.5
TOTAL EXPENSES																	1,544.2		1,475.9		1,430.6
OPERATING INCOME (LOSS)	38.5		127.1		70.5		41.6		41.1	[2]	136	[2]	74.1	[2]	52.8	[2]	277.7		304		317.4
Other Income (Expense)
Allowance for Equity Funds Used During Construction																	6		2.4		11
Interest Expense																	(127.9)		(123.4)		(119.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																	169.9		189.4		213.9
Income Tax Expense (Benefit)																	20.4		48.1		52.1
NET INCOME (LOSS)	10.5		89.6		38.7		13.4		11		84.1		25.1		17.3		152.2		137.5		169.7
Accounts Receivable:
Customers	24.5								70.9								24.5		70.9
Total Accounts Receivable	72.8								125.6								72.8		125.6
TOTAL CURRENT ASSETS	414.5								380.4								414.5		380.4
Property, Plant and Equipment
Transmission	1,866.9								1,679.8								1,866.9		1,679.8
Other Property, Plant and Equipment	762.7								684.1								762.7		684.1
Construction Work in Progress	199.3								233.2								199.3		233.2
Total Property, Plant and Equipment	9,680.1								9,317.8								9,680.1		9,317.8
Accumulated Depreciation and Amortization	2,808.3								2,685.8								2,808.3		2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,871.8								6,632								6,871.8		6,632
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS	342								330.5								342		330.5
TOTAL ASSETS	7,628.3								7,342.9								7,628.3		7,342.9
Current Liabilities
Accounts Payable	129.1								160.4								129.1		160.4
Affiliated Companies	64.2								63.7								64.2		63.7
Accrued Taxes	42.8								39								42.8		39
TOTAL CURRENT LIABILITIES	512.9								598.6								512.9		598.6
Liabilities, Noncurrent
Deferred Income Taxes	902.8								917.7								902.8		917.7
Regulatory Liabilities and Deferred Investment Tax Credits	923								896.4								923		896.4
TOTAL NONCURRENT LIABILITIES	4,799.8								4,509.8								4,799.8		4,509.8
TOTAL LIABILITIES	5,312.7								5,108.4								5,312.7		5,108.4
Equity [Abstract]
Retained Earnings	1,508.4								1,426.6								1,508.4		1,426.6
TOTAL LIABILITIES AND EQUITY	7,628.3								7,342.9								7,628.3		7,342.9
Operating Activites
NET INCOME (LOSS)	10.5		89.6		38.7		13.4		11		84.1		25.1		17.3		152.2		137.5		169.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																	239.5		217.4		196.5
Deferred Income Taxes																	1.2		80.5		162.6
Allowance for Equity Funds Used During Construction																	(6)		(2.4)		(11)
Change in Other Noncurrent Assets																	(18.8)		(9.2)		(13)
Increase (Decrease) in Other Noncurrent Liabilities																	46.6		17		6
Accounts Receivable, Net																	53.5		(32.9)		(5.7)
Accounts Payable																	0.9		10.5		3.5
Accrued Taxes, Net																	2.3		45.7		(68.9)
Net Cash Flows from (Used for) Operating Activities																	504.8		444.7		404.3
Investing Activities
Net Cash Flows from (Used for) Investing Activities																	(528.9)		(220.6)		(594)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																	47		(232.8)		194.8
Net Increase (Decrease) in Cash and Cash Equivalents																	22.9		(8.7)		5.1
Cash and Cash Equivalents at Beginning of Period							1.6								10.3		1.6		10.3		5.2
Cash and Cash Equivalents at End of Period	24.5								1.6								24.5		1.6		10.3
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt																	1,065.7		114.6		406.7
Repayments of Long-term Debt																	794.5		353.7		3.3
Income (Loss) from Equity Method Investment																	2.7		(3.8)		7.9
Net Income (Loss)	10.5		$ 89.6		$ 38.7		13.4		11		$ 84.1		$ 25.1		17.3		152.2		137.5		$ 169.7
Retained Earnings	$ 1,508.4								1,426.6								$ 1,508.4		$ 1,426.6
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																	1,000,000		800,000		200,000
Dilutive Securities, Effect on Basic Earnings Per Share | $ / shares																	$ 0		$ (0.01)		$ 0
Revenues [Member] | AEP Texas Inc. [Member]
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	45.00%	[9]	35.00%	[9],[10]	46.00%	[10]
Revenues [Member] | AEP Transmission Co [Member]
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	77.00%		80.00%		77.00%
Accounts Receivable [Member] | AEP Texas Inc. [Member]
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	35.00%	[9]	31.00%	[9],[10]	42.00%	[10]
Accounts Receivable [Member] | AEP Transmission Co [Member]
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk																	84.00%		85.00%	[11]	86.00%
Previously Reported [Member] | AEP Transmission Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period							0								0		$ 0		$ 0
Supplemental Income Statement Elements
Utilities Operating Expense, Depreciation and Amortization																			97.1
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																			61.2
Construction in Progress Expenditures Incurred but Not yet Paid																			473.7
Noncash Investing and Financing Activities:
Construction Expenditures Included in Current Liabilities as of December 31,																			473.7
Revenues
TOTAL REVENUES																			723.2
Expenses
Depreciation and Amortization																			97.1
TOTAL EXPENSES																			275.4
OPERATING INCOME (LOSS)																			447.8
Other Income (Expense)
Allowance for Equity Funds Used During Construction																			52.3
Interest Expense																			(68)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																			433.3
Income Tax Expense (Benefit)																			147.2
NET INCOME (LOSS)																			286.1
Accounts Receivable:
Customers									19.1										19.1
Total Accounts Receivable									113.6										113.6
Accrued Tax Benefits									46.6										46.6
TOTAL CURRENT ASSETS									327.7										327.7
Property, Plant and Equipment
Transmission									5,336.1										5,336.1
Other Property, Plant and Equipment									131.4										131.4
Construction Work in Progress									1,312.7										1,312.7
Total Property, Plant and Equipment									6,780.2										6,780.2
Accumulated Depreciation and Amortization									170.4										170.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET									6,609.8										6,609.8
Other Noncurrent Assets
Deferred Property Taxes									117.8										117.8
TOTAL OTHER NONCURRENT ASSETS									130.6										130.6
TOTAL ASSETS									7,068.1										7,068.1
Current Liabilities
Accounts Payable									473.2										473.2
Affiliated Companies									52.9										52.9
Accrued Taxes									225.4										225.4
TOTAL CURRENT LIABILITIES									836.3										836.3
Liabilities, Noncurrent
Deferred Income Taxes									601.7										601.7
Regulatory Liabilities and Deferred Investment Tax Credits									493.7										493.7
TOTAL NONCURRENT LIABILITIES									3,626.5										3,626.5
TOTAL LIABILITIES									4,462.8										4,462.8
Equity [Abstract]
Retained Earnings									788.7										788.7
TOTAL MEMBER'S EQUITY									2,605.3										2,605.3
TOTAL LIABILITIES AND EQUITY									7,068.1										7,068.1
Operating Activites
NET INCOME (LOSS)																			286.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																			97.1
Deferred Income Taxes																			272.8
Allowance for Equity Funds Used During Construction																			(52.3)
Amortization of Deferred Property Taxes																			(15.6)
Change in Other Noncurrent Assets																			9.8
Increase (Decrease) in Other Noncurrent Liabilities																			27.3
Accounts Receivable, Net																			(34.5)
Accounts Payable																			9.8
Accrued Taxes, Net																			13
Net Cash Flows from (Used for) Operating Activities																			604.8
Investing Activities
Net Cash Flows from (Used for) Investing Activities																			(1,595.6)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																			990.8
Net Increase (Decrease) in Cash and Cash Equivalents																			0
Cash and Cash Equivalents at Beginning of Period							0								0		0		0
Cash and Cash Equivalents at End of Period									0										0		$ 0
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)																			286.1
Retained Earnings									788.7										788.7
Revision [Member] | AEP Transmission Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period							0								0		0		0
Supplemental Income Statement Elements
Utilities Operating Expense, Depreciation and Amortization																			(1.4)
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts																			1.2
Construction in Progress Expenditures Incurred but Not yet Paid																			11.3
Noncash Investing and Financing Activities:
Construction Expenditures Included in Current Liabilities as of December 31,																			11.3
Revenues
TOTAL REVENUES																			(16.3)
Expenses
Depreciation and Amortization																			(1.4)
TOTAL EXPENSES																			(1.4)
OPERATING INCOME (LOSS)																			(14.9)
Other Income (Expense)
Allowance for Equity Funds Used During Construction																			(3.3)
Interest Expense																			(2.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)																			(20.4)
Income Tax Expense (Benefit)																			(5)
NET INCOME (LOSS)																			(15.4)
Accounts Receivable:
Customers									(4.1)										(4.1)
Total Accounts Receivable									(4.1)										(4.1)
Accrued Tax Benefits									2.8										2.8
TOTAL CURRENT ASSETS									(1.3)										(1.3)
Property, Plant and Equipment
Transmission									(16.4)										(16.4)
Other Property, Plant and Equipment									(4.6)										(4.6)
Construction Work in Progress									11.3										11.3
Total Property, Plant and Equipment									(9.7)										(9.7)
Accumulated Depreciation and Amortization									(17.8)										(17.8)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET									8.1										8.1
Other Noncurrent Assets
Deferred Property Taxes									7.2										7.2
TOTAL OTHER NONCURRENT ASSETS									7.2										7.2
TOTAL ASSETS									14										14
Current Liabilities
Accounts Payable									11.3										11.3
Affiliated Companies									13.2										13.2
Accrued Taxes									6.1										6.1
TOTAL CURRENT LIABILITIES									30.6										30.6
Liabilities, Noncurrent
Deferred Income Taxes									(1.3)										(1.3)
Regulatory Liabilities and Deferred Investment Tax Credits									0.1										0.1
TOTAL NONCURRENT LIABILITIES									(1.2)										(1.2)
TOTAL LIABILITIES									29.4										29.4
Equity [Abstract]
Retained Earnings									(15.4)										(15.4)
TOTAL MEMBER'S EQUITY									(15.4)										(15.4)
TOTAL LIABILITIES AND EQUITY									14										14
Operating Activites
NET INCOME (LOSS)																			(15.4)
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization																			(1.4)
Deferred Income Taxes																			(1.3)
Allowance for Equity Funds Used During Construction																			3.3
Amortization of Deferred Property Taxes																			(7.2)
Change in Other Noncurrent Assets																			1.2
Increase (Decrease) in Other Noncurrent Liabilities																			0.2
Accounts Receivable, Net																			4.1
Accounts Payable																			13.2
Accrued Taxes, Net																			3.3
Net Cash Flows from (Used for) Operating Activities																			0
Investing Activities
Net Cash Flows from (Used for) Investing Activities																			0
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from (Used for) Financing Activities																			0
Net Increase (Decrease) in Cash and Cash Equivalents																			0
Cash and Cash Equivalents at Beginning of Period							$ 0								$ 0		$ 0		0
Cash and Cash Equivalents at End of Period									0										$ 0		$ 0
Organization and Summary of Significant Accounting Policies (Textuals)
Error Corrections and Prior Period Adjustments, Description																			The $(20) million adjustment to pretax income for the year ended December 31, 2017 includes adjustments of $(12) million relating to 2016 and earlier periods. The effect of recording this adjustment of $(12) million in 2017 is not material to AEPTCo’s financial statements for 2017 or any earlier period				AEPTCo recorded a pretax out of period correction of an error of approximately $17 million related to revenue recorded from 2013 through March 31, 2018 in the second quarter of 2018	The impact of this misstatement reduced AEPTCo’s pretax income by approximately $7 million on a cumulative basis for the period 2011 through June 30, 2018
Net Income (Loss)																			$ (15.4)
Retained Earnings									$ (15.4)										$ (15.4)
[1]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[2]	Amounts reflect the adoption of ASU 2017-07 “Compensation - Retirement Benefits”. See Note 2 - New Accounting Pronouncements for additional information.
[3]	(a)Reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see “Revisions to Previously Issued Financial Statements” below.
[4]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[5]	The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1.
[6]	The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[7]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[8]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[9]	Just Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer.
[10]	TXU Energy did not meet the Total Revenue threshold of 10% in order to be considered a significant customer.
[11]	Reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

New Accounting Pronouncements_2

New Accounting Pronouncements New Accounting Pronouncements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
AEP Texas Inc. [Member]
Estimated Future Operating Lease Obligation	$ 80.2
AEP Transmission Co [Member]
Estimated Future Operating Lease Obligation	5.4
Appalachian Power Co [Member]
Estimated Future Operating Lease Obligation	80.4
Indiana Michigan Power Co [Member]
Estimated Future Operating Lease Obligation	351.1
Ohio Power Co [Member]
Estimated Future Operating Lease Obligation	76.8
Public Service Co Of Oklahoma [Member]
Estimated Future Operating Lease Obligation	32.2
Southwestern Electric Power Co [Member]
Estimated Future Operating Lease Obligation	$ 35.8

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		$ (67.8)	$ (156.3)	$ (127.1)
Change in Fair Value Recognized in AOCI		6.6	71.2	(28)
Commodity
Generation and Marketing Revenues		16,195.7	15,424.9	16,380.1
Interest Rate
Interest Expense		984.4	895	877.2
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(38.3)	26.4	(1.7)
Income Tax (Expense) Benefit		(115.3)	(969.7)	73.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(30.3)	17.3	(1.2)
Net Current Period Other Comprehensive Income (Loss)		(23.7)	88.5	(29.2)
ASU 2018-02 Adoption		(3)
ASU 2016-01 Adoption		0
Ending Balance in AOCI		(120.4)	(67.8)	(156.3)
Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		11.9	8.4	7.1
Change in Fair Value Recognized in AOCI		0	3.5	1.3
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	3.5	1.3
ASU 2018-02 Adoption	[1]	0
ASU 2016-01 Adoption	[1]	(11.9)
Ending Balance in AOCI		0	11.9	8.4
Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		141.6	140.5	139.9
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(6.7)	1.7	0.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(5.3)	1.1	0.6
Net Current Period Other Comprehensive Income (Loss)		(5.3)	1.1	0.6
ASU 2018-02 Adoption	[1]	0
ASU 2016-01 Adoption	[1]	0
Ending Balance in AOCI		136.3	141.6	140.5
Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(179.9)	(266.4)	(251.7)
Change in Fair Value Recognized in AOCI		(33)	86.5	(14.7)
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)		(33)	86.5	(14.7)
ASU 2018-02 Adoption	[1]	(8.2)
ASU 2016-01 Adoption	[1]	0
Ending Balance in AOCI		(221.1)	(179.9)	(266.4)
Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(23.7)	88.5	(29.2)
ASU 2018-02 Adoption	[1]	(17)
ASU 2016-01 Adoption	[1]	(11.9)
Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(28.4)	(23.1)	(5.2)
Change in Fair Value Recognized in AOCI		37.3	(20.4)	(14.6)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(32.7)	23.2	(5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(25.8)	15.1	(3.3)
Net Current Period Other Comprehensive Income (Loss)		11.5	(5.3)	(17.9)
ASU 2018-02 Adoption	[1]	(6.1)
ASU 2016-01 Adoption	[1]	0
Ending Balance in AOCI		(23)	(28.4)	(23.1)
Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(13)	(15.7)	(17.2)
Change in Fair Value Recognized in AOCI		2.3	1.6	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		1.1	1.5	2.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0.8	1.1	1.5
Net Current Period Other Comprehensive Income (Loss)		3.1	2.7	1.5
ASU 2018-02 Adoption	[1]	(2.7)
ASU 2016-01 Adoption	[1]	0
Ending Balance in AOCI		(12.6)	(13)	(15.7)
Generation and Marketing Revenues [Member]
Commodity
Generation and Marketing Revenues		1,818.1	1,771.4	2,858.7
Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		3,427.1	2,965.3	2,821.4
Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	1.1	1.5	2.4
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(19.5)	(19.6)	(19.4)
Amortization of Actuarial (Gains) Losses		12.8	21.3	20.3
Income Tax (Expense) Benefit		(8)	9.1	(0.5)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Interest Rate
Interest Expense	[2]	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) Benefit		0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(19.5)	(19.6)	(19.4)
Amortization of Actuarial (Gains) Losses		12.8	21.3	20.3
Income Tax (Expense) Benefit		(1.4)	0.6	0.3
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	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) Benefit		0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	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) Benefit		(6.9)	8.1	(1.7)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	1.1	1.5	2.4
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0.3	0.4	0.9
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Commodity
Generation and Marketing Revenues	[2]	(0.1)	(5.6)	(21.4)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Securities Available for Sale [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Generation and Marketing Revenues	[2]	(0.1)	(5.6)	(21.4)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale	[2]	(32.6)	28.8	16.4
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Securities Available for Sale [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale	[2]	(32.6)	28.8	16.4
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
AEP Texas Inc. [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(12.6)	(14.9)	(17.2)
Change in Fair Value Recognized in AOCI		(1)	1.1	0.8
Commodity
Generation and Marketing Revenues		1,493
Interest Rate
Interest Expense		147.3	142.3	144.4
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		1.6	1.7	2.2
Income Tax (Expense) Benefit		(20.8)	23.4	(59.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1.2	1.2	1.5
Net Current Period Other Comprehensive Income (Loss)		0.2	2.3	2.3
ASU 2018-02 Adoption		(0.9)
Ending Balance in AOCI		(15.1)	(12.6)	(14.9)
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		4.5	4.2	3.9
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0.3	0.4	0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0.2	0.3	0.3
Net Current Period Other Comprehensive Income (Loss)		0.2	0.3	0.3
ASU 2018-02 Adoption	[1]	0
Ending Balance in AOCI		4.7	4.5	4.2
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		(12.6)	(13.7)	(14.6)
Change in Fair Value Recognized in AOCI		(1)	1.1	0.9
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)		(1)	1.1	0.9
ASU 2018-02 Adoption	[1]	(1.8)
Ending Balance in AOCI		(15.4)	(12.6)	(13.7)
AEP Texas Inc. [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		0.2	2.3	2.3
ASU 2018-02 Adoption	[1]	(2.7)
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		(4.5)	(5.4)	(6.5)
Change in Fair Value Recognized in AOCI		0	0	(0.1)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		1.3	1.3	1.8
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1	0.9	1.2
Net Current Period Other Comprehensive Income (Loss)		1	0.9	1.1
ASU 2018-02 Adoption	[1]	(0.9)
Ending Balance in AOCI		(4.4)	(4.5)	(5.4)
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	1.3	1.3	1.8
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains) Losses		0.4	0.5	0.5
Income Tax (Expense) Benefit		0.4	0.5	0.7
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains) Losses		0.4	0.5	0.5
Income Tax (Expense) Benefit		0.1	0.1	0.1
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	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) Benefit		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	[2]	1.3	1.3	1.8
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0.3	0.4	0.6
Appalachian Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		1.3	(8.4)	(2.8)
Change in Fair Value Recognized in AOCI		(3.3)	11.6	(3.5)
Commodity
Generation and Marketing Revenues		2,993.2
Interest Rate
Interest Expense		194.8	190.9	188.5
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(4.1)	(2.9)	(3.2)
Income Tax (Expense) Benefit		44.9	(185.3)	(199.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(3.3)	(1.9)	(2.1)
Net Current Period Other Comprehensive Income (Loss)		(6.6)	9.7	(5.6)
ASU 2018-02 Adoption		0.4
Ending Balance in AOCI		(5)	1.3	(8.4)
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		14.8	16	17.4
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(3.9)	(1.8)	(2.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(3.1)	(1.2)	(1.4)
Net Current Period Other Comprehensive Income (Loss)		(3.1)	(1.2)	(1.4)
ASU 2018-02 Adoption	[1]	0
Ending Balance in AOCI		11.7	14.8	16
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		(15.7)	(27.3)	(23.8)
Change in Fair Value Recognized in AOCI		(2.6)	11.6	(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)		(2.6)	11.6	(3.5)
ASU 2018-02 Adoption	[1]	(0.2)
Ending Balance in AOCI		(18.5)	(15.7)	(27.3)
Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(6.6)	9.7	(5.6)
ASU 2018-02 Adoption	[1]	0.3
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0
Change in Fair Value Recognized in AOCI		(0.7)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0.7
Net Current Period Other Comprehensive Income (Loss)		0
ASU 2018-02 Adoption	[1]	0
Ending Balance in AOCI		0	0
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		2.2	2.9	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)	(1.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(0.9)	(0.7)	(0.7)
Net Current Period Other Comprehensive Income (Loss)		(0.9)	(0.7)	(0.7)
ASU 2018-02 Adoption	[1]	0.5
Ending Balance in AOCI		1.8	2.2	2.9
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		503.5	357.6	329.3
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	(1.1)	(1.1)	(1.1)
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(5.2)	(5.2)	(5.1)
Amortization of Actuarial (Gains) Losses		1.3	3.4	3
Income Tax (Expense) Benefit		(0.8)	(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	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(5.2)	(5.2)	(5.1)
Amortization of Actuarial (Gains) Losses		1.3	3.4	3
Income Tax (Expense) Benefit		(0.8)	(0.6)	(0.7)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	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) Benefit		0	0	0
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0
Amortization of Actuarial (Gains) Losses		0
Income Tax (Expense) Benefit		0.2
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(1.1)	(1.1)	(1.1)
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		(0.2)	(0.4)	(0.4)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale	[2]	0.9
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Purchased Electricity for Resale	[2]	0
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Purchased Electricity for Resale	[2]	0
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale	[2]	0.9
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale	[2]	0
Indiana Michigan Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(12.1)	(16.2)	(16.7)
Change in Fair Value Recognized in AOCI		(0.6)	2.8	(0.8)
Commodity
Generation and Marketing Revenues		2,381
Interest Rate
Interest Expense		124.1	110.8	100.8
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		2	2	2
Income Tax (Expense) Benefit		(29.1)	(81.4)	(67.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1.6	1.3	1.3
Net Current Period Other Comprehensive Income (Loss)		1	4.1	0.5
ASU 2018-02 Adoption		(2.4)
Ending Balance in AOCI		(13.8)	(12.1)	(16.2)
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
ASU 2018-02 Adoption	[1]	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		(6.5)	(9.3)	(8.5)
Change in Fair Value Recognized in AOCI		(0.6)	2.8	(0.8)
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)		(0.6)	2.8	(0.8)
ASU 2018-02 Adoption	[1]	(0.3)
Ending Balance in AOCI		(7.4)	(6.5)	(9.3)
Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		1	4.1	0.5
ASU 2018-02 Adoption	[1]	(2.7)
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		(10.7)	(12)	(13.3)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		2	2	2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1.6	1.3	1.3
Net Current Period Other Comprehensive Income (Loss)		1.6	1.3	1.3
ASU 2018-02 Adoption	[1]	(2.4)
Ending Balance in AOCI		(11.5)	(10.7)	(12)
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		221.8	152.2	198.7
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	2	2	2
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.8)	(0.9)	(0.8)
Amortization of Actuarial (Gains) Losses		0.8	0.9	0.8
Income Tax (Expense) Benefit		0.4	0.7	0.7
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	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.8)	(0.9)	(0.8)
Amortization of Actuarial (Gains) Losses		0.8	0.9	0.8
Income Tax (Expense) Benefit		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	[2]	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) Benefit		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	2	2
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0.4	0.7	0.7
Ohio Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		1.9
Commodity
Generation and Marketing Revenues		3,079.9
Interest Rate
Interest Expense		100.7	101.9	112.2
Pension and OPEB
Income Tax (Expense) Benefit		(24)	(159.3)	(143.8)
Net Current Period Other Comprehensive Income (Loss)		(1.3)	(1.1)	(1.3)
ASU 2018-02 Adoption		0.4
Ending Balance in AOCI		1	1.9
Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(1.3)	(1.1)	(1.3)
ASU 2018-02 Adoption		0.4
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		1.9	3	4.3
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(1.7)	(1.7)	(1.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(1.3)	(1.1)	(1.3)
Net Current Period Other Comprehensive Income (Loss)		(1.3)	(1.1)	(1.3)
ASU 2018-02 Adoption	[1]	0.4
Ending Balance in AOCI		1	1.9	3
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		684.6	705.9	663.1
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(1.7)	(1.7)	(1.9)
Pension and OPEB
Income Tax (Expense) Benefit		(0.4)	(0.6)	(0.6)
Public Service Co Of Oklahoma [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		2.6
Commodity
Generation and Marketing Revenues		1,536.4
Interest Rate
Interest Expense		63.5	53.4	51.2
Pension and OPEB
Income Tax (Expense) Benefit		(5)	(50.1)	(54.4)
Net Current Period Other Comprehensive Income (Loss)		(1)	(0.8)	(0.8)
ASU 2018-02 Adoption		0.5
Ending Balance in AOCI		2.1	2.6
Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(1)	(0.8)	(0.8)
ASU 2018-02 Adoption		0.5
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		2.6	3.4	4.2
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(1.3)	(1.3)	(1.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(1)	(0.8)	(0.8)
Net Current Period Other Comprehensive Income (Loss)		(1)	(0.8)	(0.8)
ASU 2018-02 Adoption	[1]	0.5
Ending Balance in AOCI		2.1	2.6	3.4
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		479.9	514.9	441.2
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(1.3)	(1.3)	(1.2)
Pension and OPEB
Income Tax (Expense) Benefit		(0.3)	(0.5)	(0.4)
Southwestern Electric Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(4)	(9.4)	(9.4)
Change in Fair Value Recognized in AOCI		(0.8)	4.7	(1)
Commodity
Generation and Marketing Revenues		1,817
Interest Rate
Interest Expense		127.9	123.4	119.7
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0.3	1.1	1.6
Income Tax (Expense) Benefit		(20.4)	(48.1)	(52.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0.3	0.7	1
Net Current Period Other Comprehensive Income (Loss)		(0.5)	5.4	0
ASU 2018-02 Adoption		(1.3)
Ending Balance in AOCI		(5.4)	(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		1.2	1.9	2.6
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(1.8)	(1.1)	(1.1)
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)	(0.7)
ASU 2018-02 Adoption	[1]	0
Ending Balance in AOCI		(0.2)	1.2	1.9
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		0.8	(3.9)	(2.9)
Change in Fair Value Recognized in AOCI		(3.1)	4.7	(1)
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)		(3.1)	4.7	(1)
ASU 2018-02 Adoption	[1]	0.4
Ending Balance in AOCI		(1.9)	0.8	(3.9)
Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(0.5)	5.4
ASU 2018-02 Adoption	[1]	(0.9)
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		(6)	(7.4)	(9.1)
Change in Fair Value Recognized in AOCI		2.3	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		2.1	2.2	2.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1.7	1.4	1.7
Net Current Period Other Comprehensive Income (Loss)		4	1.4	1.7
ASU 2018-02 Adoption	[1]	(1.3)
Ending Balance in AOCI		(3.3)	(6)	(7.4)
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		177.1	168.7	142.4
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	2.1	2.2	2.7
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(2)	(2)	(1.8)
Amortization of Actuarial (Gains) Losses		0.2	0.9	0.7
Income Tax (Expense) Benefit		0	0.4	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	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(2)	(2)	(1.8)
Amortization of Actuarial (Gains) Losses		0.2	0.9	0.7
Income Tax (Expense) Benefit		(0.4)	(0.4)	(0.4)
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	[2]	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) Benefit		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]	2.1	2.2	2.7
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		$ 0.4	$ 0.8	$ 1
[1]	See Note 2 - New Accounting Pronouncements for additional information.
[2]	Amounts reclassified to the referenced line item on the statements of income.

Rate Matters - East Companies

Rate Matters - East Companies (Details)	1 Months Ended	12 Months Ended
	Jan. 31, 2019USD ($)	Dec. 31, 2018USD ($)MW	Dec. 31, 2017USD ($)
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 4,393,900,000	$ 4,120,700,000
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		490,200,000	483,000,000
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		465,300,000	460,200,000
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		432,100,000	$ 410,100,000
Virginia Legislation Affecting Biennial Reviews [Member]
Public Utilities, General Disclosures [Line Items]
Fuel Expenses Not to be Recovered		10,000,000
Reduction in Annual Base Rates		50,000,000
Energy Efficiency Programs to be Requested from The Virginia SCC Through July, 2028 (in $'s)		$ 140,000,000
Energy Efficiency Programs to be Requested from The Virginia SCC Through July, 2028 (in MW's) | MW		200
Percent of Excess Earnings Subject to Refund		70.00%
Basis Points Over Authorized Return on Equity Considered Excess Earnings		70.00%
Approved Return on Common Equity		9.42%
Virginia Legislation Affecting Biennial Reviews [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Fuel Expenses Not to be Recovered		$ 10,000,000
Reduction in Annual Base Rates		50,000,000
Energy Efficiency Programs to be Requested from The Virginia SCC Through July, 2028 (in $'s)		$ 140,000,000
Energy Efficiency Programs to be Requested from The Virginia SCC Through July, 2028 (in MW's) | MW		200
Percent of Excess Earnings Subject to Refund		70.00%
Basis Points Over Authorized Return on Equity Considered Excess Earnings		70.00%
Approved Return on Common Equity		9.42%
Virginia Staff Depreciation Study Request [Member]
Public Utilities, General Disclosures [Line Items]
Potential Increase to Total Annual Depreciation Rates		$ 21,000,000
Potential Increase to Annual Transmission Depreciation Rates		6,000,000
Virginia Staff Depreciation Study Request [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Potential Increase to Total Annual Depreciation Rates		21,000,000
Potential Increase to Annual Transmission Depreciation Rates		6,000,000
Virginia Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Not Subject to Rate Normalization Requirements to Offset Fuel		55,000,000
Reduction in Annual Base Rates due to Tax Reform		50,000,000
Refund Due to Tax Reform		7,000,000
Refund for Current Year Tax Reform Rate Change		39,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property		7,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		11,000,000
Staff Recommended Reduction in Annual Base Rates due to Tax Reform		69,000,000
Staff Recommended Refund for Current Year Tax Reform Rate Change		41,000,000
Staff Recommended Refund for Excess ADIT Associated with Certain Depreciable Property		9,000,000
Staff Recommended Refund for Excess ADIT Not Subject to Rate Normalization Requirements		19,000,000
Staff Recommended One Time Refund of Estimated Excess Taxes Collected		23,000,000
Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Not Subject to Rate Normalization Requirements to Offset Fuel		55,000,000
Reduction in Annual Base Rates due to Tax Reform		50,000,000
Refund Due to Tax Reform		7,000,000
Refund for Current Year Tax Reform Rate Change		39,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property		7,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		11,000,000
Staff Recommended Reduction in Annual Base Rates due to Tax Reform		69,000,000
Staff Recommended Refund for Current Year Tax Reform Rate Change		41,000,000
Staff Recommended Refund for Excess ADIT Associated with Certain Depreciable Property		9,000,000
Staff Recommended Refund for Excess ADIT Not Subject to Rate Normalization Requirements		19,000,000
Staff Recommended One Time Refund of Estimated Excess Taxes Collected		23,000,000
2018 West Virginia Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		115,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 24,000,000
Requested Return on Common Equity		10.22%
Settled Amount of Increase Related to Annual Depreciation Rates		$ 18,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		14,000,000
Amount Of Increased Depreciation Expense Requested		32,000,000
Adjusted Annual Increase Request due to Tax Reform		95,000,000
Setlled Annual Increase		$ 44,000,000
Settled Return on Common Equity		9.75%
2018 West Virginia Base Rate Case [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 98,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 19,000,000
Requested Return on Common Equity		10.22%
Settled Amount of Increase Related to Annual Depreciation Rates		$ 14,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		12,000,000
Amount Of Increased Depreciation Expense Requested		28,000,000
Adjusted Annual Increase Request due to Tax Reform		80,000,000
Setlled Annual Increase		$ 36,000,000
Settled Return on Common Equity		9.75%
West Virginia Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change		$ 63,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		139,000,000
West Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change		51,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		125,000,000
2017 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 263,000,000
Requested Return on Common Equity		10.60%
Setlled Annual Increase		$ 97,000,000
Settled Return on Common Equity		9.95%
2017 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 263,000,000
Requested Return on Common Equity		10.60%
Setlled Annual Increase		$ 97,000,000
Settled Return on Common Equity		9.95%
2017 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 52,000,000
Requested Return on Common Equity		10.60%
Approved Annual Revenue Increase		$ 50,000,000
Approved Return on Common Equity		9.90%
ALJ Recommended Annual Increase		$ 49,000,000
ALJ Recommended Return on Common Equity		9.80%
Reduced Capacity Charge Pretax Loss		$ 9,000,000
Alternate Supplier Cap		10.00%
Cost of New Entry Value		$ 289
2017 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 52,000,000
Requested Return on Common Equity		10.60%
Approved Annual Revenue Increase		$ 50,000,000
Approved Return on Common Equity		9.90%
ALJ Recommended Annual Increase		$ 49,000,000
ALJ Recommended Return on Common Equity		9.80%
Reduced Capacity Charge Pretax Loss		$ 9,000,000
Alternate Supplier Cap		10.00%
Cost of New Entry Value		$ 289
Michigan Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		9,000,000
Refund for Current Year Tax Reform Rate Change		3,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property		68,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		37,000,000
Michigan Tax Reform [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		9,000,000
Refund for Current Year Tax Reform Rate Change		3,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property		68,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		37,000,000
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member]
Public Utilities, General Disclosures [Line Items]
Approved Capital Costs		274,000,000
Projected Capital Costs		274,000,000
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Capital Costs		274,000,000
Projected Capital Costs		274,000,000
2017 Kentucky Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
KPSC Order Annual Revenue Increase		$ 12,000,000
KPSC Order Return on Common Equity		9.70%
KPSC Order Annual Revenue Reduction due to Tax Reform		$ 14,000,000
KPSC Order Deferral of Rockport Plant Unit Power Agreement Expenses		$ 50,000,000
Recovery/Return of certain PJM OATT Expenses Above/Below Corresponding Level Recovered in Rates		80.00%
KPCo Request for Additional Revenue Increase		$ 765,000
Kentucky Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Associated with Certain Depreciable Property		82,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 93,000,000
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		$ 15,000,000
Return on Common Equity Proposed in the Amended ESP Filing		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		$ 15,000,000
Return on Common Equity Proposed in the Amended ESP Filing		10.00%
2016 SEET Filing [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		$ 58,000,000
Intervenor Recommended Refund to Customers		53,000,000
2016 SEET Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		58,000,000
Intervenor Recommended Refund to Customers		53,000,000
Ohio Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		20,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property		278,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		129,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		48,000,000
Ohio Tax Reform [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		20,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property		278,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		129,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		48,000,000
PJM Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Amount of RTEP Refunds Recorded to Customer Accounts Receivable		98,000,000
Amount of RTEP Refunds Recorded to Deferred Charges and Other Noncurrent Assets		$ 68,000,000
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%
Return On Common Equity Per Settlement Agreement		9.85%
Return on Common Equity Inclusive of RTO Per Settlement Agreement		10.35%
RTO Incentive Adder Per Settlement Agreement		0.50%
One Time Refund to Customers Per Settlement Agreement		$ 50,000,000
Increased Cap on Equity Portion of the Capital Structure Per Settlement Agreement		55.00%
Original Cap on Equity Portion of the Capital Structure Prior to Settlement Agreement		50.00%
Second Intervenor Recommended Return on Common Equity		8.48%
Second Intervenor Recommended One Time Refund to Customers		$ 184,000,000
FERC Trial Staff Recommended Return on Common Equity		8.41%
FERC Trial Staff Recommended One Time Refund to Customers		$ 175,000,000
Subsequent Event [Member] | Virginia Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Reduction in Refund for Current Year Tax Reform Rate Change	$ 1,000,000
Subsequent Event [Member] | Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Reduction in Refund for Current Year Tax Reform Rate Change	1,000,000
Subsequent Event [Member] | Michigan Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Ordered Refund for Current Year Tax Reform Rate Change	5,000,000
Subsequent Event [Member] | Michigan Tax Reform [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Ordered Refund for Current Year Tax Reform Rate Change	$ 5,000,000
Minimum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		215,000,000
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		215,000,000
Maximum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		290,000,000
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		$ 290,000,000

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Thousands		1 Months Ended	12 Months Ended
		Jan. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			$ 4,393,900	$ 4,120,700
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			836,200	835,700
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			94,000	111,300
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress			199,300	$ 233,200
AEP Texas Interim Transmission and Distribution Rates [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review			1,000,000
Net Increase in Transmission Rates			22,000
Increase in Transmission Rates Due to Capital Investments			46,000
Reduction In Transmission Rates Due To Tax Reform			24,000
Net Decrease In DCRF			24,000
Increase in Distribution Rates Due to Capital Investments			19,000
Refund for Current Year Tax Reform Rate Change			21,000
Refund for Excess ADIT Associated with Certain Depreciable Property			10,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements			12,000
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			1,000,000
Net Increase in Transmission Rates			22,000
Increase in Transmission Rates Due to Capital Investments			46,000
Reduction In Transmission Rates Due To Tax Reform			24,000
Net Decrease In DCRF			24,000
Increase in Distribution Rates Due to Capital Investments			19,000
Refund for Current Year Tax Reform Rate Change			21,000
Refund for Excess ADIT Associated with Certain Depreciable Property			10,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements			12,000
Hurricane Harvey and Texas Storm Cost Securitization [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates			1,000
AEP Texas Total Deferred Storm-Related Costs			152,000
AEP Texas Hurricane Harvey Deferred Storm-Related Costs			128,600
AEP Texas Hurricane Harvey Capital Restoration Costs Incurred			219,100
AEP Texas Hurricane Harvey O&M Restoration Costs Incurred			136,900
AEP Texas Hurricane Harvey Total Restoration Costs Incurred			356,000
AEP Texas Hurricane Harvey Incremental O&M Costs			(129,800)
AEP Texas Hurricane Harvey Incremental Deferred O&M Costs			129,800
AEP Texas Hurricane Harvey Insurance Proceeds Received Relating to Capital			(12,700)
AEP Texas Hurricane Harvey Insurance Proceeds Received Relating to Regulatory Assets			(1,200)
AEP Texas Hurricane Harvey Storm Insurance Proceeds Received			(13,900)
AEP Texas Hurricane Harvey Storm-Capital Expenditures, Net			206,400
AEP Texas Hurricane Harvey Total O&M Storm Costs, Net			7,100
AEP Texas Hurricane Harvey Total Storm Costs, Net			342,100
Determination of System Restoration Costs for Total Estimated Storm Costs			424,600
Determination of System Restoration Costs for Total Estimated Storm Costs Net of Offsets			369,600
Amount of Permanent Storm Restoration Reduction			5,000
Amount of Disallowed Charges not Directly Related to Storm Restoration			4,000
Amount of Disallowed Charges due to Additional Insurance Proceeds Received			5,100
Total Estimated Hurricane Harvey Storm Costs - DSRC			356,000
Estimated Hurricane Harvey Carrying Costs - DSRC			31,500
Estimated Litigation Costs - DSRC			600
Non-Hurricane Harvey Storm Restoration Costs - DSRC			36,500
Tax Credit - DSRC			(800)
Insurance Proceeds - DSRC			(8,700)
Excess ADIT - DSRC	[1]		(45,500)
Settlement Agreement Adjustments - DSRC			(10,600)
Incremental Insurance Proceeds Received			(5,100)
Total Estimated Storm Costs Per Settlement Agreement - DSRC			353,900
Amount of Securitization Request for Distribution Related Assets			247,000
Amount of Transmission Related Assets to be Recovered at a Later Time			107,000
Hurricane Harvey and Texas Storm Cost Securitization [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates			1,000
AEP Texas Total Deferred Storm-Related Costs			152,000
AEP Texas Hurricane Harvey Deferred Storm-Related Costs			128,600
AEP Texas Hurricane Harvey Capital Restoration Costs Incurred			219,100
AEP Texas Hurricane Harvey O&M Restoration Costs Incurred			136,900
AEP Texas Hurricane Harvey Total Restoration Costs Incurred			356,000
AEP Texas Hurricane Harvey Incremental O&M Costs			(129,800)
AEP Texas Hurricane Harvey Incremental Deferred O&M Costs			129,800
AEP Texas Hurricane Harvey Insurance Proceeds Received Relating to Capital			(12,700)
AEP Texas Hurricane Harvey Insurance Proceeds Received Relating to Regulatory Assets			(1,200)
AEP Texas Hurricane Harvey Storm Insurance Proceeds Received			(13,900)
AEP Texas Hurricane Harvey Storm-Capital Expenditures, Net			206,400
AEP Texas Hurricane Harvey Total O&M Storm Costs, Net			7,100
AEP Texas Hurricane Harvey Total Storm Costs, Net			342,100
Determination of System Restoration Costs for Total Estimated Storm Costs			424,600
Determination of System Restoration Costs for Total Estimated Storm Costs Net of Offsets			369,600
Amount of Permanent Storm Restoration Reduction			5,000
Amount of Disallowed Charges not Directly Related to Storm Restoration			4,000
Amount of Disallowed Charges due to Additional Insurance Proceeds Received			5,100
Total Estimated Hurricane Harvey Storm Costs - DSRC			356,000
Estimated Hurricane Harvey Carrying Costs - DSRC			31,500
Estimated Litigation Costs - DSRC			600
Non-Hurricane Harvey Storm Restoration Costs - DSRC			36,500
Tax Credit - DSRC			(800)
Insurance Proceeds - DSRC			(8,700)
Excess ADIT - DSRC	[1]		(45,500)
Settlement Agreement Adjustments - DSRC			(10,600)
Incremental Insurance Proceeds Received			(5,100)
Total Estimated Storm Costs Per Settlement Agreement - DSRC			353,900
Amount of Securitization Request for Distribution Related Assets			247,000
Amount of Transmission Related Assets to be Recovered at a Later Time			107,000
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Reduction In Transmission Rates Due To Tax Reform			28,000
Refund for Current Year Tax Reform Rate Change			$ 11,000
Parent Equity Ownership Interest in ETT			50.00%
AEP Share of ETT Cumulative Revenues Subject to Review			$ 884,000
2018 Oklahoma Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 88,000
Requested Return on Common Equity			10.30%
Amount Of Increased Depreciation Expense Requested			$ 13,000
Amount of Increase Related to Increased Storm Expense Amortization			7,000
2018 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			$ 88,000
Requested Return on Common Equity			10.30%
Amount Of Increased Depreciation Expense Requested			$ 13,000
Amount of Increase Related to Increased Storm Expense Amortization			7,000
Oklahoma Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			3,000
Refund for Excess ADIT Associated with Certain Depreciable Property			353,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements			72,000
Oklahoma Tax Reform [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			3,000
Refund for Excess ADIT Associated with Certain Depreciable Property			353,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements			72,000
2012 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances			114,000
Resulting Approved Base Rate Increase			$ 52,000
Texas Jurisdictional Share of Turk Plant			33.00%
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances			$ 114,000
Resulting Approved Base Rate Increase			$ 52,000
Texas Jurisdictional Share of Turk Plant			33.00%
2012 Texas Base Rate Case [Member] | Turk Generating Plant [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net			$ 1,500,000
2012 Texas Base Rate Case [Member] | Turk Generating Plant [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net			$ 1,500,000
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			$ 69,000
Approved Net Increase in Texas Annual Revenues			50,000
Approved Additional Vegetation Management Expenses			2,000
Impairment Charge Total			19,000
Impairment Charge Welsh Plant, Unit 2			7,000
Impairment Charge Disallowed Plant Investments			12,000
Additional Revenues Recognized to be Surcharged to Customers			32,000
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management			7,000
Proposed Revenue Reduction Due to Tax Reform			18,000
Approved Reduction in Residential Rates Due to Tax Reform			$ 8,000
Approved Return on Common Equity			9.60%
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			$ 69,000
Approved Net Increase in Texas Annual Revenues			50,000
Approved Additional Vegetation Management Expenses			2,000
Impairment Charge Total			19,000
Impairment Charge Welsh Plant, Unit 2			7,000
Impairment Charge Disallowed Plant Investments			12,000
Additional Revenues Recognized to be Surcharged to Customers			32,000
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management			7,000
Proposed Revenue Reduction Due to Tax Reform			18,000
Approved Reduction in Residential Rates Due to Tax Reform			$ 8,000
Approved Return on Common Equity			9.60%
Texas Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			$ 10,000
Texas Tax Reform [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			10,000
2015 Louisiana Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			14,000
2015 Louisiana Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			14,000
2017 Louisiana Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			31,000
Resulting Approved Base Rate Increase			31,000
2017 Louisiana Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase			31,000
Resulting Approved Base Rate Increase			31,000
2018 Louisiana Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			11,000
Requested Annual Increase			28,000
Adjusted Requested Annual Increase			18,000
2018 Louisiana Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			11,000
Requested Annual Increase			28,000
Adjusted Requested Annual Increase			18,000
Welsh Plant - Environmental Impact [Member] | Welsh Plant, Units 1 and 3 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net			629,000
Projected Capital Costs			550,000
Construction Work in Progress			399,000
Total Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs			131,000
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs			79,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals			10,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity			5,000
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			629,000
Projected Capital Costs			550,000
Construction Work in Progress			399,000
Total Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs			131,000
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs			79,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals			10,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity			5,000
Arkansas Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			7,000
Refund for Excess ADIT Associated with Certain Depreciable Property			66,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements			11,000
Refund Due to Tax Reform			655
Arkansas Tax Reform [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change			7,000
Refund for Excess ADIT Associated with Certain Depreciable Property			66,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements			11,000
Refund Due to Tax Reform			$ 655
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%
Second Intervenor Recommended Return on Common Equity			8.71%
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%
Agreed Upon Return on Common Equity			10.10%
Agreed Upon One-Time Billing Credit			$ 287
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Staff Recommended Annual Increase		$ 57,000
Staff Recommended Return on Common Equity		9.00%
Oklaunion Power Station Estimated Net Book Value at Retirement		$ 49,000
Intervenor Recommended Refund of SPP Rider		9,000
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ (6,000)
Intervenor Recommended Return on Common Equity		9.30%
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ 34,000
Intervenor Recommended Return on Common Equity		9.36%
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Staff Recommended Annual Increase		$ 57,000
Staff Recommended Return on Common Equity		9.00%
Oklaunion Power Station Estimated Net Book Value at Retirement		$ 49,000
Intervenor Recommended Refund of SPP Rider		9,000
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ (6,000)
Intervenor Recommended Return on Common Equity		9.30%
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ 34,000
Intervenor Recommended Return on Common Equity		9.36%
[1]	(a)Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements.

Effects of Regulation (Details)

Effects of Regulation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Regulated Generating Unit to be Retired
Gross Investment		$ 21,699.9	$ 20,760.5
Accumulated Depreciation and Amortization		17,986.1	17,167
Total Property, Plant and Equipment, Net		55,099.1	50,261.5
Materials and Supplies		579.6	565.5
Regulatory Assets
Current Regulatory Assets		150.1	292.5
Noncurrent Regulatory Assets		3,310.4	3,587.6
Regulatory Liabilities
Current Regulatory Liabilities		58.6	11.9
Noncurrent Regulatory Liabilities		8,540.3	8,422.3
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 17,986.1	$ 17,167
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
AEP Texas Inc. [Member]
Regulated Generating Unit to be Retired
Gross Investment		$ 352.1	$ 350.7
Accumulated Depreciation and Amortization		1,651.2	1,594.5
Total Property, Plant and Equipment, Net		7,991.8	6,825.1
Materials and Supplies		52.8	52
Regulatory Assets
Noncurrent Regulatory Assets		430	378.7
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,344.3	1,320.5
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 1,651.2	$ 1,594.5
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
AEP Transmission Co [Member]
Regulated Generating Unit to be Retired
Accumulated Depreciation and Amortization		$ 271.9	$ 152.6	[1]
Total Property, Plant and Equipment, Net		7,996.2	6,617.9	[1],[2]
Materials and Supplies		19	13.6
Regulatory Assets
Noncurrent Regulatory Assets		12.9	11.7
Regulatory Liabilities
Noncurrent Regulatory Liabilities		521.3	493.8
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 271.9	$ 152.6	[1]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
Appalachian Power Co [Member]
Regulated Generating Unit to be Retired
Gross Investment		$ 6,509.6	$ 6,446.9
Accumulated Depreciation and Amortization		4,124.4	3,896.4
Total Property, Plant and Equipment, Net		10,668.3	10,245.1
Materials and Supplies		100.1	99.5
Regulatory Assets
Current Regulatory Assets		99.6	88.8
Noncurrent Regulatory Assets		475.8	573.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,449.7	1,454.9
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 4,124.4	$ 3,896.4
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
Indiana Michigan Power Co [Member]
Regulated Generating Unit to be Retired
Gross Investment		$ 4,887.2	$ 4,445.9
Accumulated Depreciation and Amortization		3,151.6	3,024.2
Total Property, Plant and Equipment, Net		6,611.2	6,050.4
Materials and Supplies		167.3	160.6
Regulatory Assets
Current Regulatory Assets		0	15
Noncurrent Regulatory Assets		512.5	579.4
Regulatory Liabilities
Current Regulatory Liabilities		27.4	2.7
Noncurrent Regulatory Liabilities		1,574.5	1,708.7
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 3,151.6	$ 3,024.2
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
Ohio Power Co [Member]
Regulated Generating Unit to be Retired
Accumulated Depreciation and Amortization		$ 2,218.6	$ 2,184.8
Total Property, Plant and Equipment, Net		6,274.9	5,766.8
Materials and Supplies		42.9	41.9
Regulatory Assets
Current Regulatory Assets		0.4	115.9
Noncurrent Regulatory Assets		387.5	652.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,221.2	1,100.2
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 2,218.6	$ 2,184.8
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
Public Service Co Of Oklahoma [Member]
Regulated Generating Unit to be Retired
Gross Investment		$ 1,577	$ 1,577.2
Accumulated Depreciation and Amortization		1,472.9	1,393.6
Total Property, Plant and Equipment, Net		3,966.7	3,886.2
Materials and Supplies		44.8	42
Regulatory Assets
Current Regulatory Assets		0	36.7
Noncurrent Regulatory Assets		369	368.1
Regulatory Liabilities
Current Regulatory Liabilities		20.1	0
Noncurrent Regulatory Liabilities		864.7	853.5
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 1,472.9	$ 1,393.6
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
Southwestern Electric Power Co [Member]
Regulated Generating Unit to be Retired
Gross Investment		$ 4,672.6	$ 4,624.9
Accumulated Depreciation and Amortization		2,808.3	2,685.8
Total Property, Plant and Equipment, Net		6,871.8	6,632
Materials and Supplies		67.5	67.9
Regulatory Assets
Current Regulatory Assets		18.8	14.1
Noncurrent Regulatory Assets		230.8	220.6
Regulatory Liabilities
Current Regulatory Liabilities		11.1	8.7
Noncurrent Regulatory Liabilities		923	896.4
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 2,808.3	$ 2,685.8
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%		35.00%
Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 6,819.8	$ 2,787.4
Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		925.8	638.9
Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		442.9	1.6
Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		897.8	279.4
Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,408.9	981.1
Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,221	432.9
Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		864.7	313.7
Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		616	183.2
Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,720.5	5,634.9
Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	418.5	681.6
Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4]	78.4	492.2
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	551.9	1,175.5
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	165.6	727.6
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	667.3
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	0	539.8
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	307	713.2
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,477.8	1,338.2
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		56.8	58.9
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		106.4	17.9
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		953.9	1,033.8
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		148.4	65.6
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		54	53
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		9.4	13.4
Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.2
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
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		2,838.1	2,671.1
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		660	618.7
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		99.5	66.7
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		619.3	616.7
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		182.5	202.2
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		505.8	430.2
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		276.8	268.8
Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		440.3	427.1
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9]	2,503.9	(1,221.9)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	209	(38.7)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4]	343.4	(65.1)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	172.1	(355.2)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	272.5	(254.9)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	566.8	(62.9)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	533.9	(8.1)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	166.3	(257.3)
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9]	1,720.3	5,634.7
Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	0	667.1
Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[11]	288	322
Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		152.6	123.4
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[12]	44.9	49.4
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3.3	79.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1	0
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		6	3.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		64.4	64.9
Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3,022.4	3,265.6
Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		277.4	255.3
Regulatory Assets Approved for Recovery [Member] | AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		12.9	11.7
Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		430.9	524.5
Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		509.2	500.1
Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		386.5	652.8
Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		363	364.8
Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		166.4	155.7
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		79.6	59.9
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		9	9.1
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		5.5	0
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		50.6	50.8
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,139.5	1,293.8
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		85.4	78.4
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		86.5	98
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		318.7	252.3
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		71	326.8
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		257.1	253.7
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		21.4	7.2
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		208.4	262.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		35.9	40.3
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		0.5	3.3
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		13.8	14.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,882.9	1,971.8
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		192	176.9
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		344.4	426.5
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		190.5	247.8
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		315.5	326
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		105.9	111.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		145	148.5
Oklaunion Power Station [Member] | Generating Units Probable of Abandonment [Member]
Regulated Generating Unit to be Retired
Gross Investment		106.6
Accumulated Depreciation and Amortization		62.8
Total Property, Plant and Equipment, Net		43.8
Oklaunion Power Station Accelerated Depreciation	[13]	5.5
Materials and Supplies		3.1
Cost of Removal Regulatory Liability		$ 5
Expected Retirement Date		2,020
Remaining Recovery Period, Plant Depreciation		28 years
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 62.8
Oklaunion Power Station [Member] | Generating Units Probable of Abandonment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Unit to be Retired
Gross Investment		106.6
Accumulated Depreciation and Amortization		62.8
Total Property, Plant and Equipment, Net		43.8
Oklaunion Power Station Accelerated Depreciation		5.5
Materials and Supplies		3.1
Cost of Removal Regulatory Liability		$ 5
Expected Retirement Date		2,020
Remaining Recovery Period, Plant Depreciation		28 years
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		$ 62.8
Plant Retirement Costs - Unrecovered Plant [Member]
Regulated Generating Unit to be Retired
Accumulated Depreciation and Amortization		91
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Appalachian Power Co [Member]
Regulated Generating Unit to be Retired
Accumulated Depreciation and Amortization		91
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	50.3
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	50.3
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 680.9	682.6
Regulatory Asset, Amortization Period		25 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		$ 85.3	86.3
Regulatory Asset, Amortization Period		25 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		$ 232.2	245.3
Regulatory Asset, Amortization Period		10 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		$ 153.4	138.5
Regulatory Asset, Amortization Period		22 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		$ 17.1	17.6
Regulatory Asset, Amortization Period		23 years
Kentucky Deferred Purchase Power Expenses [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 14.5	0
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	9.1
Oklaunion Power Station Accelerated Depreciation [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		5.5	0
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		14.8	9.6
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		0.3	0.5
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		20.7	42.2
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
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		3.3	2
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1	0
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		0.5	3.3
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		3.6	2.5
Storm Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 31.1	39.3
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		$ 31.1	39
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	[14]	$ 152.4	128
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	[3]	152.4	123.3
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.3	44.2
Regulatory Asset, Amortization Period		5 years
Asset Retirement Obligation Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 64.3	34.3
Regulatory Asset, Amortization Period		22 years
Asset Retirement Obligation Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 35.3	39.7
Asset Retirement Obligation Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		35.3	39.7
Asset Retirement Obligation Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 21.6	37.2
Regulatory Asset, Amortization Period		22 years
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 35	0
Regulatory Asset, Amortization Period		15 years
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 35	0
Regulatory Asset, Amortization Period		15 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		$ 0	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		0	36.3
Cook Plant Turbine [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.8	0
Regulatory Asset, Amortization Period		20 years
Cook Plant Turbine [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.8	0
Regulatory Asset, Amortization Period		20 years
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	15.9
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		0	15.9
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		0.2	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		4.9	4.3
Michigan Deferred Cook Plant Life Cycle Management Project Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 16.1	0
Regulatory Asset, Amortization Period		16 years
Michigan Deferred Cook Plant Life Cycle Management Project Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 16.1	0
Regulatory Asset, Amortization Period		16 years
Michigan Deferred Cook Plant Life Cycle Management Project Costs [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		$ 0	14.7
Rockport Plant Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.5	0
Regulatory Asset, Amortization Period		9 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		$ 0	10.4
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		5.3	4
Shipe Road Transmission Project [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	3.3
Meter Replacement Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 74.4	83.7
Regulatory Asset, Amortization Period		9 years
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		$ 40.1	44.9
Regulatory Asset, Amortization Period		9 years
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		$ 34.3	38.8
Regulatory Asset, Amortization Period		9 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 57.8	172.6
Regulatory Asset, Amortization Period		1 year
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		$ 57.8	172.6
Regulatory Asset, Amortization Period		1 year
Over-Recovery of Costs Related to Advanced Metering [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 45.3	33.5
Regulatory Asset, Amortization Period		2 years
Over-Recovery of Costs Related to Advanced Metering [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 45.3	33.5
Regulatory Asset, Amortization Period		2 years
Environmental Controls Projects [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 43.4	28.1
Regulatory Asset, Amortization Period		22 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		$ 29.2	28.1
Regulatory Asset, Amortization Period		22 years
Environmental Controls Projects [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 14.2	0
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		0	15.3
Mitchell Plant Transfer [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 17	17.8
Regulatory Asset, Amortization Period		22 years
Distribution Decoupling [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.3	61.7
Regulatory Asset, Amortization Period		2 years
Distribution Decoupling [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.3	61.7
Regulatory Asset, Amortization Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 68.8	0
Remaining Refund Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 68.8	0
Remaining Refund Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	90.8
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		0	90.8
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		$ 0.6	7.8
Regulatory Asset, Amortization Period		1 year
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		$ 5.7	6
Regulatory Asset, Amortization Period		20 years
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		$ 8.6	8.8
Regulatory Asset, Amortization Period		38 years
Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 134.2	129.9
Regulatory Asset, Amortization Period		30 years
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		$ 6	7.7
Regulatory Asset, Amortization Period		19 years
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		$ 89.3	93.2
Regulatory Asset, Amortization Period		27 years
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		$ 18.7	9.5
Regulatory Asset, Amortization Period		30 years
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		$ 6.5	7.8
Regulatory Asset, Amortization Period		20 years
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		$ 4.3	5
Regulatory Asset, Amortization Period		14 years
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		$ 7.4	4.7
Regulatory Asset, Amortization Period		25 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		$ 104.6	139.3
Regulatory Asset, Amortization Period		14 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		$ 100.2	131.8
Regulatory Asset, Amortization Period		14 years
Cook Nuclear Plant Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 37.5	66.7
Regulatory Asset, Amortization Period		3 years
Cook Nuclear Plant 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		$ 37.5	66.7
Regulatory Asset, Amortization Period		3 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 35.6	39.1
Regulatory Asset, Amortization Period		4 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	18.8
Regulatory Asset, Amortization Period		4 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		$ 6.5	9.7
Regulatory Asset, Amortization Period		4 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.9	7.2
Regulatory Asset, Amortization Period		4 years
Peak Demand/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 31.9	40.1
Regulatory Asset, Amortization Period		8 years
Peak Demand/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.7	18.1
Regulatory Asset, Amortization Period		8 years
Peak Demand/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		$ 6.3	13
Regulatory Asset, Amortization Period		2 years
Vegetation Management [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 26.6	33.5
Regulatory Asset, Amortization Period		3 years
Vegetation Management [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 26.6	33.5
Regulatory Asset, Amortization Period		3 years
PJM/SPP Annual Formula Rate True Up [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 22	11.7
Regulatory Asset, Amortization Period		2 years
PJM/SPP Annual Formula Rate True Up [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.9	11.7
Regulatory Asset, Amortization Period		2 years
PJM Costs and Off-system Sales Margin Sharing [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 20.1	57
Regulatory Asset, Amortization Period		2 years
PJM Costs and Off-system Sales Margin Sharing [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 20.1	57
Regulatory Asset, Amortization Period		2 years
Transmission Rate Adjustment Clause [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.3	0
Remaining Refund Period		2 years
Transmission Rate Adjustment Clause [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	32.6
Transmission Rate Adjustment Clause [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	32.6
Virginia Generation Rate Adjustment Clause [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.3	7.3
Regulatory Asset, Amortization Period		2 years
Smart Grid Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.1	0
Regulatory Asset, Amortization Period		2 years
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9],[15]	$ 2,925.7	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[16],[17]	251.8	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4],[18]	453.4	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5],[19]	453.5	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6],[20]	362	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10],[21]	350.5	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7],[22]	415.2	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8],[23]	370.5	0
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9]	1,025.3	4,256.7
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	277.1	578.3
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4]	73.9	512.8
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	268.2	794.4
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	125	534.6
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	0	436.3
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	0	447.7
Excess ADIT Associated with Certain Depreciable Property [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	280.1	650.5
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9]	$ 864.3	0
Remaining Refund Period		18 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4]	$ (28.5)	0
Remaining Refund Period		10 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	$ 84.5	0
Remaining Refund Period		10 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	$ 192.6	0
Remaining Refund Period		10 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	$ 279.1	0
Remaining Refund Period		10 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	$ 126.4	0
Remaining Refund Period		10 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	$ 54.3	0
Remaining Refund Period		2 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9]	$ 695	1,378
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	141.4	103.3
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4]	4.5	(20.6)
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	283.7	381.1
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	40.6	193
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	0	230.8
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	0	92.1
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	26.9	62.7
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[9]	$ (1,286.1)	(1,221.9)
Remaining Refund Period		56 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	$ (42.8)	(38.7)
Remaining Refund Period		31 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[4],[24]	$ (81.5)	(65.1)
Remaining Refund Period		52 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	$ (365.9)	(355.2)
Remaining Refund Period		26 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[6]	$ (282.1)	(254.9)
Remaining Refund Period		26 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[10]	$ (62.8)	(62.9)
Remaining Refund Period		29 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[7]	$ (7.7)	(8.1)
Remaining Refund Period		27 years
Income Taxes Subject to Flow Through [Member] | Income Tax Related Regulatory Liabilities [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	$ (258.5)	(257.3)
Remaining Refund Period		31 years
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[25]	$ 2,742.8	2,637.1
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	[26]	645.2	599.2
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	[27]	99.5	66.7
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	[28]	618.3	615.8
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	[29]	182.5	202.2
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	[30]	436.6	428.8
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	[31]	276.8	268.8
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	[32]	437.8	424.5
Excess Earnings [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 8.9	9.4
Remaining Refund Period		35 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 204.9	191.2
Remaining Refund Period		44 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		$ 10.8	12.3
Remaining Refund Period		44 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		$ 29.4	34.1
Remaining Refund Period		21 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		$ 51.5	50.7
Remaining Refund Period		26 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		$ 4.5	5.9
Remaining Refund Period		13 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 8.7	10.6
Remaining Refund Period		42 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		$ 1	0.9
Remaining Refund Period		42 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	[33]	$ 828.5	945
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	[34]	828.5	945
PJM Transmission Enhancement Refund [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 164.2	0
Remaining Refund Period		7 years
PJM Transmission Enhancement Refund [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 47.7	0
Remaining Refund Period		7 years
PJM Transmission Enhancement Refund [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 29.1	0
Remaining Refund Period		7 years
PJM Transmission Enhancement Refund [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 71.3	0
Remaining Refund Period		7 years
Stranded Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 46	46
Remaining Refund Period		6 years
Stranded Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 46	46
Remaining Refund Period		6 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 45.9	15
Remaining Refund Period		6 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		$ 34.7	9.5
Remaining Refund Period		6 years
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[33]	$ 42.9	43.2
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	[34]	42.9	43.2
Energy Efficiency/Peak Demand Reduction [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 17.5	25.6
Remaining Refund Period		3 years
Energy Efficiency/Peak Demand Reduction [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 14.9	23.6
Remaining Refund Period		2 years
Distribution Investment Rider [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 7.8	0.3
Remaining Refund Period		2 years
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 22.9	3.2
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		$ 22.9	2.7
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 35.7	8.7
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 4.5	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 20.1	0
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		$ 11.1	8.7
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 101.7	203.1
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		$ 82.4	21.4
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		$ 0	15
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Ohio Power Co [Member]
Regulatory Assets
Current Regulatory Assets	[35]	$ 0.4	115.9
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		$ 0	36.7
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 18.8	14.1
Regulatory Asset, Amortization Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 48.4	89.4
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		$ 17.2	67.4
Regulatory Asset, Amortization Period		1 year
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 46.1	49.4
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.6	3.9
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		2.4	1
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.9	1.7
Other Regulatory Assets Being Recovered [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	0.5
Other Regulatory Assets Being Recovered [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	7.2
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		83	111.7
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		7.4	8.5
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		8.3	22
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		16.7	20
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		11.3	8.6
Other Regulatory Assets Being Recovered [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		9.6	4.1
Other Regulatory Assets Being Recovered [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		8.9	6.2
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		$ 1.4	16.3
Regulatory Asset, Amortization Period		2 years
Under-Recovery of 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		$ 1.7	9.5
Regulatory Asset, Amortization Period		2 years
Other Regulatory Liabilities Not Yet Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0.2	0.2
Other Regulatory Liabilities Not Yet Being Paid [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
Advanced Metering Infrastructure Surcharge [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 8.5	12.7
Remaining Refund Period		2 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		$ 8.5	12.7
Remaining Refund Period		2 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		$ 6.3	6.8
Remaining Refund Period		13 years
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 84.8	41.6
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.6
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		3.9	1.9
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		24	11.5
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		11.3	11.1
Other Regulatory Liabilities Being Paid [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		2.5	2.3
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		4.9	7.5
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.4	1.3
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.4	1.4
Other Regulatory Liabilities Being Paid [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		2.5	2.6
Enhanced Service Reliability Plan [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 43.1	30.6
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		$ 43.1	30.6
Remaining Refund Period		2 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		$ 129
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		129
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		0	32.2
Over-Recovered Customer 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		$ 8.8	6.5
Remaining Refund Period		1 year
Environmental Controls Projects [Member] | Pension Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Regulatory Asset, Amortization Period		14 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		$ 1,326.6	1,196.3
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		$ 176.9	151.2
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		$ 172.2	168.8
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		$ 84.9	77.8
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		$ 181.5	170.6
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		$ 84.3	72.7
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		$ 108.4	101
Regulatory Asset, Amortization Period		12 years
Other Postretirement Benefit Plans [Member] | Statement Of Financial Accounting Standards 106 Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 27.9	32.5
Regulatory Asset, Amortization Period		6 years
Other Postretirement Benefit Plans [Member] | Statement Of Financial Accounting Standards 106 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		$ 6.1	7.1
Regulatory Asset, Amortization Period		6 years
Other Postretirement Benefit Plans [Member] | Statement Of Financial Accounting Standards 106 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		$ 3.2	$ 3.7
Regulatory Asset, Amortization Period		6 years
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[3]	As of December 31, 2018, AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information.
[4]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[5]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[6]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[7]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[8]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[9]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[10]	This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform” section of Note 12 for additional information.
[11]	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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates.
[12]	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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates.
[13]	(a)In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station. See “2018 Oklahoma Base Rate Case” section of Note 4 for additional information.
[14]	As of December 31, 2018, AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information.
[15]	Refunded using ARAM.
[16]	Refunded using ARAM.
[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. See “Federal Tax Reform” section of Note 12 for additional information.
[18]	Refunded using ARAM.
[19]	Refunded using ARAM.
[20]	Refunded using ARAM.
[21]	Refunded using ARAM.
[22]	Refunded using ARAM.
[23]	Refunded using ARAM.
[24]	The 2017 balance reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters.
[25]	Relieved as removal costs are incurred.
[26]	Relieved as removal costs are incurred.
[27]	Relieved as removal costs are incurred.
[28]	Relieved as removal costs are incurred.
[29]	Relieved as removal costs are incurred.
[30]	Relieved as removal costs are incurred.
[31]	Relieved as removal costs are incurred.
[32]	Relieved as removal costs are incurred.
[33]	Relieved when plant is decommissioned.
[34]	Relieved when plant is decommissioned.
[35]	December 31, 2017 balance includes PIRR.

Commitments, Guarantees and C_3

Commitments, Guarantees and Contingencies (Details) - USD ($)		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 31, 2019
Contractual Commitments
Less than 1 year		$ 1,321,400,000
For 2-3 years		1,484,300,000
For 4-5 years		631,000,000
After 5 years		1,472,200,000
Total Contractual Commitments		4,908,900,000
Commitments, Guarantees and Contingencies (Textuals)
Revolving Credit Facilities		4,000,000,000
Disposal, Assessed Fees and Related Interest	[1]	273,600,000	$ 268,600,000
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		60,600,000
Pollution Control Bonds Supported by Bilateral Letters of Credit
Variable Rate PCBs Supported		45,000,000
Commitments, Guarantees and Contingencies (Textuals)
Letters of Credit Limit		1,200,000,000
Uncommitted Facility		305,000,000
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals)
Guarantees of Mine Reclamation, Amount		140,000,000
Estimated Final Cost Mine Reclamation		107,000,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		75,000,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		80,000,000
Amount Collected, Rider Mine Close Other Assets Noncurrent		5,000,000
Equity Method Investee [Member]
Commitments, Guarantees and Contingencies (Textuals)
Maximum Potential Amount of Future Payments Associated with Guarantee		75,000,000
Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	1,081,700,000
For 2-3 years	[2]	1,020,700,000
For 4-5 years	[2]	306,700,000
After 5 years	[2]	135,000,000
Total Contractual Commitments	[2]	2,544,100,000
Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		239,700,000
For 2-3 years		463,600,000
For 4-5 years		324,300,000
After 5 years		1,337,200,000
Total Contractual Commitments		2,364,800,000
AEP Texas Inc. [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	[3]	2,800,000
AEP Texas Inc. [Member] | Letters of Credit [Member] | Subsequent Event [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility					$ 2,200,000
Appalachian Power Co [Member]
Contractual Commitments
Less than 1 year		428,800,000
For 2-3 years		462,100,000
For 4-5 years		82,400,000
After 5 years		318,200,000
Total Contractual Commitments		1,291,500,000
Appalachian Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	391,800,000
For 2-3 years	[2]	390,100,000
For 4-5 years	[2]	8,400,000
After 5 years	[2]	500,000
Total Contractual Commitments	[2]	790,800,000
Appalachian Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		37,000,000
For 2-3 years		72,000,000
For 4-5 years		74,000,000
After 5 years		317,700,000
Total Contractual Commitments		500,700,000
Indiana Michigan Power Co [Member]
Contractual Commitments
Less than 1 year		378,200,000
For 2-3 years		557,100,000
For 4-5 years		354,200,000
After 5 years		406,100,000
Total Contractual Commitments		1,695,600,000
Commitments, Guarantees and Contingencies (Textuals)
Disposal, Assessed Fees and Related Interest	[1]	273,600,000	268,600,000
Indiana Michigan Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	251,400,000
For 2-3 years	[2]	293,100,000
For 4-5 years	[2]	187,800,000
After 5 years	[2]	83,800,000
Total Contractual Commitments	[2]	816,100,000
Indiana Michigan Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		126,800,000
For 2-3 years		264,000,000
For 4-5 years		166,400,000
After 5 years		322,300,000
Total Contractual Commitments		879,500,000
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		600,000
Ohio Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		31,000,000
For 2-3 years		59,200,000
For 4-5 years		60,200,000
After 5 years		338,600,000
Total Contractual Commitments		489,000,000
Public Service Co Of Oklahoma [Member]
Contractual Commitments
Less than 1 year		151,400,000
For 2-3 years		251,900,000
For 4-5 years		95,400,000
After 5 years		226,200,000
Total Contractual Commitments		724,900,000
Public Service Co Of Oklahoma [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	58,400,000
For 2-3 years	[2]	69,700,000
For 4-5 years	[2]	20,100,000
After 5 years	[2]	0
Total Contractual Commitments	[2]	148,200,000
Public Service Co Of Oklahoma [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		93,000,000
For 2-3 years		182,200,000
For 4-5 years		75,300,000
After 5 years		226,200,000
Total Contractual Commitments		576,700,000
Southwestern Electric Power Co [Member]
Contractual Commitments
Less than 1 year		142,200,000
For 2-3 years		194,500,000
For 4-5 years		82,800,000
After 5 years		125,800,000
Total Contractual Commitments		545,300,000
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals)
Guarantees of Mine Reclamation, Amount		140,000,000
Estimated Final Cost Mine Reclamation		107,000,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		75,000,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		80,000,000
Amount Collected, Rider Mine Close Other Assets Noncurrent		5,000,000
Southwestern Electric Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	108,800,000
For 2-3 years	[2]	132,100,000
For 4-5 years	[2]	32,600,000
After 5 years	[2]	0
Total Contractual Commitments	[2]	273,500,000
Southwestern Electric Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		33,400,000
For 2-3 years		62,400,000
For 4-5 years		50,200,000
After 5 years		125,800,000
Total Contractual Commitments		271,800,000
Decommissioning and Low Level Waste Accumulation Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals)
Cost of Decommissioning and Disposal of Radioactive Waste		2,000,000,000
Additional Ongoing Costs for Post Decommissioning Storage of SNF		6,000,000
Subsequent Decommissioning of the Spent Fuel Storage Facility		37,000,000
Amount Recovered in Rates for Decommissioning Costs		8,000,000	9,000,000	$ 9,000,000
Decommissioning Fund Investments, Fair Value		2,200,000,000	2,200,000,000
Decommissioning and Low Level Waste Accumulation Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals)
Cost of Decommissioning and Disposal of Radioactive Waste		2,000,000,000
Additional Ongoing Costs for Post Decommissioning Storage of SNF		6,000,000
Subsequent Decommissioning of the Spent Fuel Storage Facility		37,000,000
Amount Recovered in Rates for Decommissioning Costs		8,000,000	9,000,000	9,000,000
Decommissioning Fund Investments, Fair Value		2,200,000,000	2,200,000,000
Spent Nuclear Fuel Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals)
DOE SNF Disposal Fee		0
Disposal, Assessed Fees and Related Interest		274,000,000	269,000,000
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		317,000,000	312,000,000
Recovery of Spent Nuclear Fuel Storage Costs		11,000,000	22,000,000	6,000,000
Current Amount Recoverable from the Federal Government		8,000,000	11,000,000
Noncurrent Amount Recoverable from the Federal Government		23,000,000	5,000,000
Spent Nuclear Fuel Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals)
DOE SNF Disposal Fee		0
Disposal, Assessed Fees and Related Interest		274,000,000	269,000,000
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		317,000,000	312,000,000
Recovery of Spent Nuclear Fuel Storage Costs		11,000,000	22,000,000	$ 6,000,000
Current Amount Recoverable from the Federal Government		8,000,000	11,000,000
Noncurrent Amount Recoverable from the Federal Government		23,000,000	$ 5,000,000
Nuclear Incident Liability [Member]
Commitments, Guarantees and Contingencies (Textuals)
Insurance Coverage for Property Damage, Decommissioning and Decontamination		2,700,000,000
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,500,000,000
Contingent Financial Obligation for Mutual Insurance		50,000,000
Insurance Protection for Public Liability Arising from a Nuclear Incident		14,100,000,000
Commercially Available Insurance		450,000,000
Assessed Amount per Nuclear Incident		276,000,000
Deferred Premium Assessment Annual Payment		41,000,000
Commercially Available Insurance for Catastrophic Nature		450,000,000
Liability Coverage Under the Price-Anderson Act		13,600,000,000
Nuclear Incident Liability [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals)
Insurance Coverage for Property Damage, Decommissioning and Decontamination		2,700,000,000
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,500,000,000
Contingent Financial Obligation for Mutual Insurance		50,000,000
Insurance Protection for Public Liability Arising from a Nuclear Incident		14,100,000,000
Commercially Available Insurance		450,000,000
Assessed Amount per Nuclear Incident		276,000,000
Deferred Premium Assessment Annual Payment		41,000,000
Commercially Available Insurance for Catastrophic Nature		450,000,000
Liability Coverage Under the Price-Anderson Act		13,600,000,000
July 2019 [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit
Bilateral Letters of Credit		46,000,000
June 2022 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals)
Revolving Credit Facilities		$ 4,000,000,000
[1]	Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.
[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.
[3]	In January 2019, the letter of credit was amended to $2.2 million and the maturity date was extended until January 2020.

Dispositions, Assets and Liab_3

Dispositions, Assets and Liabilities Held for Sale and Impairments (Details)		3 Months Ended							12 Months Ended
		Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)		Mar. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2018USD ($)		Dec. 31, 2017USD ($)		Dec. 31, 2016USD ($)
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals)
Make Whole Premium on Extinguishment of Long-term Debt									$ 13,500,000		$ 46,100,000		$ 0
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges									70,600,000		87,100,000		2,267,800,000
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									0		0		(2,500,000)
Utilities Operating Expense, Operations									2,979,200,000		2,525,200,000		2,996,100,000
Vertically Integrated Utilities [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges									3,400,000		33,600,000		10,500,000
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest													0
Vertically Integrated Utilities [Member] | Tanners Creek Plant Units 1 Through 4 [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals)
Payment On Sale Of Property, Plant And Equipment											92,000,000
Vertically Integrated Utilities [Member] | Welsh Plant Unit 2 [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges											19,000,000
Vertically Integrated Utilities [Member] | Turk Generating Plant [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges											15,000,000
Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges									$ 47,700,000		53,500,000		2,257,300,000
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest													0
Generation and Marketing [Member] | Gavin, Waterford, Darby and Lawrenceburg Plants [Member]
Competitive generation assets sold to a nonaffiliated party (in MWs). | MW						5,329
Cash Proceeds from Sales of Assets, Investing Activities											2,200,000,000
Cash Proceeds from Disposition of Plant, Net											1,200,000,000
Pre-tax Gain on Sale of Plants											226,000,000
AEP Texas Inc. [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share									54.69%
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Revenue													18,200,000
Other Operation Expense													6,500,000
Maintenance Expense													3,400,000
Asset Impairments and Other Related Charges													72,700,000
Depreciation and Amortization Expense													9,800,000
Taxes Other Than Income Taxes													1,300,000
Total Expenses													93,700,000
Other Income (Expense)													(800,000)
Pretax Income of Discontinued Operations													(76,300,000)
Income Tax Expense													(27,500,000)
Total Income on Discontinued Operation as Presented on the Statements of Income													(48,800,000)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									$ 0		0		(48,800,000)
Utilities Operating Expense, Operations									488,900,000		453,100,000		457,800,000
AEP Transmission Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Utilities Operating Expense, Operations									83,800,000		60,100,000		37,000,000
Appalachian Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Utilities Operating Expense, Operations									511,600,000		503,100,000		491,700,000
Indiana Michigan Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges									0		0		10,500,000
Utilities Operating Expense, Operations									585,400,000		591,300,000		579,300,000
Ohio Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Utilities Operating Expense, Operations									771,300,000		516,000,000		711,200,000
Public Service Co Of Oklahoma [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Utilities Operating Expense, Operations									372,800,000		315,100,000		291,600,000
Southwestern Electric Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges									0		33,600,000		0
Utilities Operating Expense, Operations									$ 384,200,000		318,300,000		335,400,000
Other Assets [Member] | Corporate and Other [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Utilities Operating Expense, Operations			$ 21,000,000
I&M Price River Coal Reserves [Member] | Generation and Marketing [Member]
Asset Impairment Charges
Book Value of Impaired Assets							$ 11,000,000						11,000,000
Merchant Coal-Fired Generation Assets [Member] | Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges						$ 4,000,000	3,000,000	$ 2,139,400,000
Asset Impairment Charges
Fair Value of Impaired Assets							0						0
Book Value of Impaired Assets							2,139,400,000						2,139,400,000
Zimmer Plant Assets [Member] | Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges						$ 7,000,000
Racine Hydroelectric Plant [Member] | Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges		$ 35,000,000		$ 43,000,000
Asset Impairment Charges
Fair Value of Impaired Assets		$ 0		$ 0							$ 0
Trent and Desert Sky Wind Farms [Member] | Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges								72,700,000
Asset Impairment Charges
Fair Value of Impaired Assets							46,000,000						46,000,000
Book Value of Impaired Assets							118,700,000						118,700,000
Coal Reserves [Member] | Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges	[1]							52,800,000
Asset Impairment Charges
Fair Value of Impaired Assets							3,800,000						3,800,000
Book Value of Impaired Assets	[1]						56,600,000						56,600,000
Total Impaired Assets [Member] | Generation and Marketing [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Asset Impairments and Other Related Charges								$ 2,264,900,000
Asset Impairment Charges
Fair Value of Impaired Assets							49,800,000						49,800,000
Book Value of Impaired Assets							$ 2,314,700,000						$ 2,314,700,000
Wm. H. Zimmer Generating Station [Member] | Coal [Member] | Generation and Marketing [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share							25.40%						25.40%
Conesville Generating Station (Unit No. 4) [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share									83.50%
Conesville Generating Station (Unit No. 4) [Member] | Coal [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share				83.50%	[2],[3],[4]		43.50%		83.50%	[2],[3],[4]	83.50%	[2],[3],[4]	43.50%
J.M. Stuart Generating Station [Member] | Coal [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share							26.00%						26.00%
Oklaunion Generating Station (Unit No. 1) [Member] | AEP Texas Inc. [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share									54.70%
Oklaunion Generating Station (Unit No. 1) [Member] | Public Service Co Of Oklahoma [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share									15.60%
Oklaunion Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	[5]			70.30%					70.30%		70.30%
Oklaunion Generating Station (Unit No. 1) [Member] | Coal [Member] | AEP Texas Inc. [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share				54.70%	[5]		54.70%		54.70%	[5]	54.70%	[5]	54.70%
Oklaunion Generating Station (Unit No. 1) [Member] | Coal [Member] | Public Service Co Of Oklahoma [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	[5]			15.60%					15.60%		15.60%
[1]	(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.
[2]	Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. See the “Impairments” section of Note 7.
[3]	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%.
[4]	Operated by AGR.
[5]	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.

Benefit Plans 1 (Details)

Benefit Plans 1 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		$ 2,577.4	$ 2,553.5
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(782.6)	(830.9)
AEP Texas Inc. [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		56.3	114.8
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(104)	(63.4)
Appalachian Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		188.1	190
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(58.6)	(74.7)
Indiana Michigan Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		193	179.9
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(87.8)	(88.5)
Ohio Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		441	406.5
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(43.8)	(46.2)
Public Service Co Of Oklahoma [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		7.1	8.7
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(32.5)	(22.5)
Southwestern Electric Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		111.2	109.9
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		$ (51.4)	$ (19.9)
Pension Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	4.85%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.85%	4.80%	4.75%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 5,215.8	$ 5,085.8
Service Cost		97.6	96.5	$ 85.8
Interest Cost		187.8	203.1	211.6
Actuarial (Gain) Loss		(306.3)	182.4
Benefit Payments		(384.6)	(352)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		4,810.3	5,215.8	5,085.8
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		5,174.1	4,827.3
Actual Gain (Loss) on Plan Assets		(104.9)	600
Company Contributions	[3]	11.3	98.8
Participant Contributions		0	0
Benefit Payments		(384.6)	(352)
Fair Value of Plan Assets as of December 31		4,695.9	5,174.1	$ 4,827.3
Funded (Underfunded) Status as of December 31		(114.4)	(41.7)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	36.3
Other Current Liabilities - Accrued Short-term Benefit Liability		(5.7)	(6.2)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(108.7)	(71.8)
Funded (Underfunded) Status		(114.4)	(41.7)
Components
Net Actuarial Loss		1,355.2	1,354.2
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		88.8	(132.8)
Amortization of Actuarial Gain (Loss)		(87.8)	(82.8)
Amortization of Prior Service Credit (Cost)		0	(1)
Change for the Year		$ 1	$ (216.6)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.85%	4.80%
Company Contributions	[3]	$ 11.3	$ 98.8
Pension Plans [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[4]	0	11.6
Pension Plans [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		1,267.9	1,271.3
Pension Plans [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		18.4	17.4
Pension Plans [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 68.9	$ 53.9
Pension Plans [Member] | AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	4.95%	4.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.95%	4.90%	4.85%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 441.3	$ 421.7
Service Cost		9.2	8.6	$ 7.5
Interest Cost		16	17.1	17.8
Actuarial (Gain) Loss		(20.9)	25.6
Benefit Payments		(36.3)	(31.7)
Participant Contributions		0	0
Benefit Obligation as of December 31		409.3	441.3	421.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		455.9	416.6
Actual Gain (Loss) on Plan Assets		(9.3)	61.8
Company Contributions		0.4	9.2
Participant Contributions		0	0
Benefit Payments		(36.3)	(31.7)
Fair Value of Plan Assets as of December 31		410.7	455.9	$ 416.6
Funded (Underfunded) Status as of December 31		1.4	14.6
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		5.2	18.6
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.4)	(0.4)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(3.4)	(3.6)
Funded (Underfunded) Status		1.4	14.6
Components
Net Actuarial Loss		182	175.2
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		14	(11.1)
Amortization of Actuarial Gain (Loss)		(7.2)	(7)
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 6.8	$ (18.1)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.95%	4.90%
Company Contributions		$ 0.4	$ 9.2
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	[4]	0	2
Pension Plans [Member] | AEP Texas Inc. [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		168.2	161.4
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	2.9
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		$ 10.9	$ 8.9
Pension Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	4.75%	4.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.75%	4.60%	4.55%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 665	$ 654
Service Cost		9.3	9.4	$ 8.1
Interest Cost		23.5	25.7	27.2
Actuarial (Gain) Loss		(49.2)	15.7
Benefit Payments		(45.5)	(39.8)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		603.1	665	654
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		651.7	606.4
Actual Gain (Loss) on Plan Assets		(12.9)	74.9
Company Contributions		0	10.2
Participant Contributions		0	0
Benefit Payments		(45.5)	(39.8)
Fair Value of Plan Assets as of December 31		593.3	651.7	$ 606.4
Funded (Underfunded) Status as of December 31		(9.8)	(13.3)
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	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(9.8)	(13.3)
Funded (Underfunded) Status		(9.8)	(13.3)
Components
Net Actuarial Loss		172.2	182.5
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		0.3	(23.3)
Amortization of Actuarial Gain (Loss)		(10.6)	(10.4)
Amortization of Prior Service Credit (Cost)		0	(0.2)
Change for the Year		$ (10.3)	$ (33.9)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.75%	4.60%
Company Contributions		$ 0	$ 10.2
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	[4]	0	0.4
Pension Plans [Member] | Appalachian Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		169.6	179.9
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	0.5
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		$ 2.1	$ 1.7
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	4.90%	4.85%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.90%	4.85%	4.80%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 624.3	$ 611.6
Service Cost		13.6	14	$ 12.2
Interest Cost		22.1	24.3	25.3
Actuarial (Gain) Loss		(53.9)	10.8
Benefit Payments		(39.1)	(36.4)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		567	624.3	611.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		636.7	586.1
Actual Gain (Loss) on Plan Assets		(13.8)	74
Company Contributions		0	13
Participant Contributions		0	0
Benefit Payments		(39.1)	(36.4)
Fair Value of Plan Assets as of December 31		583.8	636.7	$ 586.1
Funded (Underfunded) Status as of December 31		16.8	12.4
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		18	13.4
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(1.2)	(1)
Funded (Underfunded) Status		16.8	12.4
Components
Net Actuarial Loss		80.6	94.9
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(4.5)	(28.6)
Amortization of Actuarial Gain (Loss)		(9.8)	(9.7)
Amortization of Prior Service Credit (Cost)		0	(0.2)
Change for the Year		$ (14.3)	$ (38.5)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.90%	4.85%
Company Contributions		$ 0	$ 13
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	[4]	0	0.4
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		78.4	91.8
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		0.5	0.7
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		$ 1.7	$ 2
Pension Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	5.00%	4.95%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	5.00%	4.95%	4.85%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 501.1	$ 492.9
Service Cost		7.7	7.5	$ 6.5
Interest Cost		17.7	19.4	20.6
Actuarial (Gain) Loss		(36.6)	13.1
Benefit Payments		(36)	(31.8)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		453.9	501.1	492.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		509.1	473.8
Actual Gain (Loss) on Plan Assets		(7)	58.9
Company Contributions		0	8.2
Participant Contributions		0	0
Benefit Payments		(36)	(31.8)
Fair Value of Plan Assets as of December 31		466.1	509.1	$ 473.8
Funded (Underfunded) Status as of December 31		12.2	8
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		12.6	8.4
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(0.4)	(0.4)
Funded (Underfunded) Status		12.2	8
Components
Net Actuarial Loss		180.7	189.6
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(0.9)	(18)
Amortization of Actuarial Gain (Loss)		(8)	(7.8)
Amortization of Prior Service Credit (Cost)		0	(0.1)
Change for the Year		$ (8.9)	$ (25.9)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5.00%	4.95%
Company Contributions		$ 0	$ 8.2
Pension Plans [Member] | Ohio Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 180.7	$ 189.6
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	4.90%	4.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.90%	4.90%	4.90%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 276.6	$ 266.7
Service Cost		7	6.4	$ 6.2
Interest Cost		9.9	10.7	11.2
Actuarial (Gain) Loss		(18.9)	10.1
Benefit Payments		(20.8)	(17.3)
Participant Contributions		0	0
Benefit Obligation as of December 31		253.8	276.6	266.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		287.8	266
Actual Gain (Loss) on Plan Assets		(5.9)	33.6
Company Contributions		0.1	5.5
Participant Contributions		0	0
Benefit Payments		(20.8)	(17.3)
Fair Value of Plan Assets as of December 31		261.2	287.8	$ 266
Funded (Underfunded) Status as of December 31		7.4	11.2
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		9.7	13.9
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.2)	(0.2)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(2.1)	(2.5)
Funded (Underfunded) Status		7.4	11.2
Components
Net Actuarial Loss		77.6	78.8
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		3.2	(7.9)
Amortization of Actuarial Gain (Loss)		(4.4)	(4.3)
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ (1.2)	$ (12.2)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.90%	4.90%
Company Contributions		$ 0.1	$ 5.5
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		$ 77.6	$ 78.8
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.65%
Interest Crediting Rate		4.00%	4.00%
Rate of Compensation Increase	[1]	4.85%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.65%	4.05%	4.30%
Interest Crediting Rate		4.00%	4.00%	4.00%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.85%	4.80%	4.75%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 314.6	$ 296.6
Service Cost		9.3	8.7	$ 8.1
Interest Cost		11.3	12.3	12.4
Actuarial (Gain) Loss		(19.2)	16.3
Benefit Payments		(24.6)	(19.3)
Participant Contributions		0	0
Benefit Obligation as of December 31		291.4	314.6	296.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		311.7	287.3
Actual Gain (Loss) on Plan Assets		(7.3)	34.6
Company Contributions		1.2	9.1
Participant Contributions		0	0
Benefit Payments		(24.6)	(19.3)
Fair Value of Plan Assets as of December 31		281	311.7	$ 287.3
Funded (Underfunded) Status as of December 31		(10.4)	(2.9)
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)	(0.2)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(10.2)	(2.7)
Funded (Underfunded) Status		(10.4)	(2.9)
Components
Net Actuarial Loss		97.4	97.4
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		5.5	(1.5)
Amortization of Actuarial Gain (Loss)		(5.5)	(4.9)
Amortization of Prior Service Credit (Cost)		0	(0.1)
Change for the Year		$ 0	$ (6.5)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.85%	4.80%
Company Contributions		$ 1.2	$ 9.1
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	[4]	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	97.4
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%
Qualified Pension Plans [Member]
Change in Fair Value of Plan Assets
Company Contributions		$ 0	93
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	93
Nonqualified Pension Plans [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		78
Benefit Obligation as of December 31			78
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Company Contributions		11	6
Fair Value of Plan Assets as of December 31		0	0
Benefit Plans (Textuals) [Abstract]
Company Contributions		11	6
Nonqualified Pension Plans [Member] | AEP Texas Inc. [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		4
Benefit Obligation as of December 31		3.8	4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] | Appalachian Power Co [Member]
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		1
Benefit Obligation as of December 31		1.2	1
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] | Ohio Power Co [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		0.4
Benefit Obligation as of December 31		0.4	0.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		2.7
Benefit Obligation as of December 31		2.3	2.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		$ 0	$ 0
Other Postretirement Benefit Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 1,332	$ 1,447.4
Service Cost		11.6	11.2	$ 10.2
Interest Cost		47.4	59.3	60.9
Actuarial (Gain) Loss		(100.1)	(97.5)
Benefit Payments		(133.6)	(128.6)
Participant Contributions		36.5	39.5
Medicare Subsidy		0.7	0.7
Benefit Obligation as of December 31		1,194.5	1,332	1,447.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		1,732.5	1,545.9
Actual Gain (Loss) on Plan Assets		(118.3)	271.6
Company Contributions	[3]	17.1	4.1
Participant Contributions		36.5	39.5
Benefit Payments		(133.6)	(128.6)
Fair Value of Plan Assets as of December 31		1,534.2	1,732.5	$ 1,545.9
Funded (Underfunded) Status as of December 31		339.7	400.5
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		392.2	463
Other Current Liabilities - Accrued Short-term Benefit Liability		(2.8)	(3.2)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(49.7)	(59.3)
Funded (Underfunded) Status		339.7	400.5
Components
Net Actuarial Loss		419.8	309.9
Prior Service Cost (Credit)		(347.2)	(416.3)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		120.4	(267.8)
Amortization of Actuarial Gain (Loss)		(10.5)	(36.7)
Amortization of Prior Service Credit (Cost)		69.1	69.1
Change for the Year		179	(235.4)
Benefit Plans (Textuals) [Abstract]
Company Contributions	[3]	17.1	4.1
Other Postretirement Benefit Plans [Member] | Income Tax Expense [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[4]	0	(3.4)
Other Postretirement Benefit Plans [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		52.5	(82.4)
Other Postretirement Benefit Plans [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		4.2	(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		$ 15.9	$ (15.6)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 107.1	$ 120.4
Service Cost		0.9	0.9	$ 0.7
Interest Cost		3.8	4.9	5.1
Actuarial (Gain) Loss		(8.3)	(11.9)
Benefit Payments		(10.7)	(10.8)
Participant Contributions		3.1	3.6
Benefit Obligation as of December 31		95.9	107.1	120.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		147.3	134.1
Actual Gain (Loss) on Plan Assets		(14.6)	20.4
Company Contributions		4.8	0
Participant Contributions		3.1	3.6
Benefit Payments		(10.7)	(10.8)
Fair Value of Plan Assets as of December 31		129.9	147.3	$ 134.1
Funded (Underfunded) Status as of December 31		34	40.2
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		34	40.2
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		34	40.2
Components
Net Actuarial Loss		38	23.9
Prior Service Cost (Credit)		(29.5)	(35.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		14.9	(23.6)
Amortization of Actuarial Gain (Loss)		(0.8)	(3.2)
Amortization of Prior Service Credit (Cost)		5.9	5.8
Change for the Year		20	(21)
Benefit Plans (Textuals) [Abstract]
Company Contributions		4.8	0
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	[4]	0	(0.2)
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		8.7	(10.2)
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	(0.3)
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		$ (0.2)	$ (0.8)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 236.5	$ 255.6
Service Cost		1.1	1.1	$ 1
Interest Cost		8.2	10.6	10.8
Actuarial (Gain) Loss		(21.9)	(13.4)
Benefit Payments		(24.7)	(24.3)
Participant Contributions		6.1	6.7
Medicare Subsidy		0.2	0.2
Benefit Obligation as of December 31		205.5	236.5	255.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		273.4	246.9
Actual Gain (Loss) on Plan Assets		(18.7)	41.6
Company Contributions		2.3	2.5
Participant Contributions		6.1	6.7
Benefit Payments		(24.7)	(24.3)
Fair Value of Plan Assets as of December 31		238.4	273.4	$ 246.9
Funded (Underfunded) Status as of December 31		32.9	36.9
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		62.3	74.6
Other Current Liabilities - Accrued Short-term Benefit Liability		(2.1)	(2.5)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(27.3)	(35.2)
Funded (Underfunded) Status		32.9	36.9
Components
Net Actuarial Loss		58.9	48
Prior Service Cost (Credit)		(50.4)	(60.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		12.8	(38.6)
Amortization of Actuarial Gain (Loss)		(1.9)	(6.3)
Amortization of Prior Service Credit (Cost)		10	10.1
Change for the Year		20.9	(34.8)
Benefit Plans (Textuals) [Abstract]
Company Contributions		2.3	2.5
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	[4]	0	(0.2)
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		2.6	(11.1)
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		1.2	(0.3)
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		$ 4.7	$ (0.8)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 153.5	$ 167.6
Service Cost		1.6	1.6	$ 1.5
Interest Cost		5.4	6.9	7
Actuarial (Gain) Loss		(10.6)	(12)
Benefit Payments		(16.2)	(15.6)
Participant Contributions		4.5	4.9
Medicare Subsidy		0.1	0.1
Benefit Obligation as of December 31		138.3	153.5	167.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		211.1	186.6
Actual Gain (Loss) on Plan Assets		(12.1)	35.2
Company Contributions		0	0
Participant Contributions		4.5	4.9
Benefit Payments		(16.2)	(15.6)
Fair Value of Plan Assets as of December 31		187.3	211.1	$ 186.6
Funded (Underfunded) Status as of December 31		49	57.6
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		49	57.6
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		49	57.6
Components
Net Actuarial Loss		54.7	42
Prior Service Cost (Credit)		(47.4)	(56.9)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		13.9	(34.9)
Amortization of Actuarial Gain (Loss)		(1.2)	(4.4)
Amortization of Prior Service Credit (Cost)		9.5	9.4
Change for the Year		22.2	(29.9)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0
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	[4]	0	(0.1)
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		6.5	(14)
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	(0.2)
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	$ (0.6)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 144.3	$ 164
Service Cost		0.9	0.9	$ 0.8
Interest Cost		5.1	6.7	7
Actuarial (Gain) Loss		(9.4)	(16.6)
Benefit Payments		(15.8)	(15.5)
Participant Contributions		4.3	4.7
Medicare Subsidy		0.1	0.1
Benefit Obligation as of December 31		129.5	144.3	164
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		198.5	182.6
Actual Gain (Loss) on Plan Assets		(11.6)	26.7
Company Contributions		0	0
Participant Contributions		4.3	4.7
Benefit Payments		(15.8)	(15.5)
Fair Value of Plan Assets as of December 31		175.4	198.5	$ 182.6
Funded (Underfunded) Status as of December 31		45.9	54.2
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		45.9	54.2
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		45.9	54.2
Components
Net Actuarial Loss		35.5	22.6
Prior Service Cost (Credit)		(34.7)	(41.6)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		14	(31.3)
Amortization of Actuarial Gain (Loss)		(1.1)	(4.3)
Amortization of Prior Service Credit (Cost)		6.9	6.9
Change for the Year		19.8	(28.7)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0
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		$ 0.8	$ (19)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 69.4	$ 77.6
Service Cost		0.7	0.7	$ 0.6
Interest Cost		2.5	3.2	3.3
Actuarial (Gain) Loss		(5.6)	(7.5)
Benefit Payments		(6.7)	(6.9)
Participant Contributions		2	2.3
Benefit Obligation as of December 31		62.3	69.4	77.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		95.5	86.4
Actual Gain (Loss) on Plan Assets		(9.2)	13.7
Company Contributions		2.7	0
Participant Contributions		2	2.3
Benefit Payments		(6.7)	(6.9)
Fair Value of Plan Assets as of December 31		84.3	95.5	$ 86.4
Funded (Underfunded) Status as of December 31		22	26.1
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		22	26.1
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		22	26.1
Components
Net Actuarial Loss		28.3	19.8
Prior Service Cost (Credit)		(21.6)	(25.9)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		9	(15.5)
Amortization of Actuarial Gain (Loss)		(0.5)	(2)
Amortization of Prior Service Credit (Cost)		4.3	4.3
Change for the Year		12.8	(13.2)
Benefit Plans (Textuals) [Abstract]
Company Contributions		2.7	0
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		$ 6.7	$ (6.1)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	3.60%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		3.60%	4.10%	4.30%
Expected Return on Plan Assets		6.00%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,024
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 80.3	$ 86.9
Service Cost		0.9	0.9	$ 0.8
Interest Cost		2.8	3.6	3.6
Actuarial (Gain) Loss		(5.9)	(6.2)
Benefit Payments		(7.7)	(7.4)
Participant Contributions		2.3	2.5
Benefit Obligation as of December 31		72.7	80.3	86.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		110.4	96.8
Actual Gain (Loss) on Plan Assets		(9.2)	18.5
Company Contributions		2.7	0
Participant Contributions		2.3	2.5
Benefit Payments		(7.7)	(7.4)
Fair Value of Plan Assets as of December 31		98.5	110.4	$ 96.8
Funded (Underfunded) Status as of December 31		25.8	30.1
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		25.8	30.1
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		25.8	30.1
Components
Net Actuarial Loss		33.9	24.7
Prior Service Cost (Credit)		(26.2)	(31.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		9.8	(18.4)
Amortization of Actuarial Gain (Loss)		(0.6)	(2.3)
Amortization of Prior Service Credit (Cost)		5.2	5.2
Change for the Year		14.4	(15.5)
Benefit Plans (Textuals) [Abstract]
Company Contributions		2.7	0
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	[4]	0	(0.4)
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		4.9	(3.7)
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		0.7	(0.6)
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		$ 2.1	$ (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]	Contributions to the qualified pension plan were $0 and $93 million for the years ended December 31, 2018 and 2017, respectively. Contributions to the nonqualified pension plans were $11 million and $6 million for the years ended December 31, 2018 and 2017, respectively.
[4]	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, 2018		Dec. 31, 2017
Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4,827.3	$ 4,695.9		$ 5,174.1
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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		5,174.1
Pension Plan [Member] | AEP Texas Inc. [Member]
Allocated Assets of Investments			8.70%		8.80%
Pension and Other Postretirement Plans' Assets
Asset Class		416.6	$ 410.7		$ 455.9
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		416.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		455.9
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	$ 593.3		$ 651.7
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		606.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		651.7
Pension Plan [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments			12.40%		12.30%
Pension and Other Postretirement Plans' Assets
Asset Class		586.1	$ 583.8		$ 636.7
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		586.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		636.7
Pension Plan [Member] | Ohio Power Co [Member]
Allocated Assets of Investments			9.90%		9.80%
Pension and Other Postretirement Plans' Assets
Asset Class		473.8	$ 466.1		$ 509.1
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		473.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		509.1
Pension Plan [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments			5.60%		5.60%
Pension and Other Postretirement Plans' Assets
Asset Class		266	$ 261.2		$ 287.8
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		266
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		287.8
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	$ 281		$ 311.7
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		287.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		311.7
Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,545.9	$ 1,534.2		$ 1,732.5
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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,732.5
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Allocated Assets of Investments			8.50%		8.50%
Pension and Other Postretirement Plans' Assets
Asset Class		134.1	$ 129.9		$ 147.3
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		134.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		147.3
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments			15.50%		15.80%
Pension and Other Postretirement Plans' Assets
Asset Class		246.9	$ 238.4		$ 273.4
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		246.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		273.4
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments			12.20%		12.20%
Pension and Other Postretirement Plans' Assets
Asset Class		186.6	$ 187.3		$ 211.1
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		186.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		211.1
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Allocated Assets of Investments			11.40%		11.50%
Pension and Other Postretirement Plans' Assets
Asset Class		182.6	$ 175.4		$ 198.5
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		182.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		198.5
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments			5.50%		5.50%
Pension and Other Postretirement Plans' Assets
Asset Class		86.4	$ 84.3		$ 95.5
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		86.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		95.5
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments			6.40%		6.40%
Pension and Other Postretirement Plans' Assets
Asset Class		96.8	$ 98.5		$ 110.4
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		96.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		110.4
Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,292.6	1,127.5		1,292.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		1,292.6
Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		339.9	393.4		339.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		339.9
Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		826.7	661.2		826.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		826.7
Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		700.4	515.6		700.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		700.4
Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		3,054.8	2,907.2		3,054.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		3,054.8
Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		692.2	625.2		692.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		692.2
Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		723.6	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		723.6
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
Transfers into Level 3		0
Transfers out of Level 3	[1]	(723.6)
Fair Value of Plan Assets as of December 31		0
Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Equity Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	1,306.1	$ 1,049.8		$ 1,306.1
Year End Allocation
Total	[2]		22.40%		25.20%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	1,306.1
Equity Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		777	$ 649.7		$ 777
Year End Allocation
Total			42.30%		44.80%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		777
Equity Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	452.9	$ 370.1		$ 452.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	452.9
Equity Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		153.6	226.2		153.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		153.6
Equity Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	826.3	661.4		826.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	826.3
Equity Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		614	419.2		614
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		614
Equity Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	26.9	18.3		26.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	26.9
Equity Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		9.4	4.3		9.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		9.4
Equity Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Equity Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Domestic [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	318.6	$ 277.3		$ 318.6
Year End Allocation
Total	[2]		5.90%		6.20%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	318.6
Domestic [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		307.1	$ 233.3		$ 307.1
Year End Allocation
Total			15.20%		17.70%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		307.1
Domestic [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Domestic [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Domestic [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	318.6	277.3		318.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	318.6
Domestic [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		307.1	233.3		307.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		307.1
Domestic [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Domestic [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Domestic [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Domestic [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
International [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	507.7	$ 384.1		$ 507.7
Year End Allocation
Total	[2]		8.20%		9.80%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	507.7
International [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		306.9	$ 185.9		$ 306.9
Year End Allocation
Total			12.10%		17.70%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		306.9
International [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
International [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
International [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	507.7	384.1		507.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	507.7
International [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		306.9	185.9		306.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		306.9
International [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
International [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
International [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
International [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Options [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	26.9	$ 18.3		$ 26.9
Year End Allocation
Total	[2]		0.40%		0.50%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	26.9
Options [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		9.4	$ 4.3		$ 9.4
Year End Allocation
Total			0.30%		0.50%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		9.4
Options [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Options [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Options [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Options [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Options [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	26.9	18.3		26.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	26.9
Options [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		9.4	4.3		9.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		9.4
Options [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Options [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Common Collective Trusts [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2],[3]	452.9	$ 370.1		$ 452.9
Year End Allocation
Total	[2],[3]		7.90%		8.70%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2],[3]	452.9
Common Collective Trusts [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	153.6	$ 226.2		$ 153.6
Year End Allocation
Total	[4]		14.70%		8.90%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	153.6
Common Collective Trusts [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2],[3]	452.9	$ 370.1		$ 452.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2],[3]	452.9
Common Collective Trusts [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	153.6	226.2		153.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	153.6
Common Collective Trusts [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2],[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2],[3]	0
Common Collective Trusts [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Common Collective Trusts [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2],[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2],[3]	0
Common Collective Trusts [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Common Collective Trusts [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2],[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2],[3]	0
Common Collective Trusts [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Fixed Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	2,992.3	$ 2,852.8		$ 2,992.3
Year End Allocation
Total	[2]		60.70%		57.80%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	2,992.3
Fixed Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		693.9	$ 622.7		$ 693.9
Year End Allocation
Total			40.60%		40.10%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		693.9
Fixed Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Fixed Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		185	163.6		185
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		185
Fixed Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0.2		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Fixed Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		49.7	42		49.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		49.7
Fixed Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	2,992.3	2,852.6		2,992.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	2,992.3
Fixed Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		459.2	417.1		459.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		459.2
Fixed Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Fixed Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Common Collective Trust - Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	185	$ 163.6		$ 185
Year End Allocation
Total	[4]		10.70%		10.70%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	185
Common Collective Trust - Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	185	$ 163.6		$ 185
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	185
Common Collective Trust - Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Common Collective Trust - Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Common Collective Trust - Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
United States Government and Agency Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	1,376.5	$ 1,512.7		$ 1,376.5
Year End Allocation
Total	[2]		32.20%		26.60%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	1,376.5
United States Government and Agency Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		187.4	$ 181.7		$ 187.4
Year End Allocation
Total			11.80%		10.80%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		187.4
United States Government and Agency Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
United States Government and Agency Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0.2		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
United States Government and Agency Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0.2		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
United States Government and Agency Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	1,376.5	1,512.5		1,376.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	1,376.5
United States Government and Agency Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		187.4	181.5		187.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		187.4
United States Government and Agency Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Corporate Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	1,277	$ 1,082.9		$ 1,277
Year End Allocation
Total	[2]		23.00%		24.70%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	1,277
Corporate Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		214.1	$ 188.6		$ 214.1
Year End Allocation
Total			12.30%		12.40%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		214.1
Corporate Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Corporate Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Corporate Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Corporate Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Corporate Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	1,277	1,082.9		1,277
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	1,277
Corporate Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		214.1	188.6		214.1
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		214.1
Corporate Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Corporate Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Foreign Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	296.9	$ 221.6		$ 296.9
Year End Allocation
Total	[2]		4.70%		5.70%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	296.9
Foreign Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		40.7	$ 35		$ 40.7
Year End Allocation
Total			2.30%		2.40%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		40.7
Foreign Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Foreign Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Foreign Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Foreign Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Foreign Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	296.9	221.6		296.9
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	296.9
Foreign Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		40.7	35		40.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		40.7
Foreign Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Foreign Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
State and Local Government [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	31.7	$ 28.2		$ 31.7
Year End Allocation
Total	[2]		0.60%		0.60%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	31.7
State and Local Government [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		66.5	$ 53.6		$ 66.5
Year End Allocation
Total			3.50%		3.80%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		66.5
State and Local Government [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
State and Local Government [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
State and Local Government [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
State and Local Government [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		49.7	41.8		49.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		49.7
State and Local Government [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	31.7	28.2		31.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	31.7
State and Local Government [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		16.8	11.8		16.8
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		16.8
State and Local Government [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Other - Asset Backed [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	10.2	$ 7.4		$ 10.2
Year End Allocation
Total	[2]		0.20%		0.20%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	10.2
Other - Asset Backed [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0.2	$ 0.2		$ 0.2
Year End Allocation
Total			0.00%		0.00%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0.2
Other - Asset Backed [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Other - Asset Backed [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Other - Asset Backed [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Other - Asset Backed [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Other - Asset Backed [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	10.2	7.4		10.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	10.2
Other - Asset Backed [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0.2	0.2		0.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0.2
Other - Asset Backed [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[2]	0
Other - Asset Backed [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Infrastructure [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	59.5	$ 72.2		$ 59.5
Year End Allocation
Total	[3]		1.50%		1.20%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	59.5
Infrastructure [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	59.5	$ 72.2		$ 59.5
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	59.5
Infrastructure [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Infrastructure [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Infrastructure [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		57.6	0	[3]	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		57.6
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
Transfers into Level 3		0
Transfers out of Level 3	[1]	(57.6)
Fair Value of Plan Assets as of December 31	[3]	0
Real Estate [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	290.3	$ 220.4		$ 290.3
Year End Allocation
Total	[3]		4.70%		5.60%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	290.3
Real Estate [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	290.3	$ 220.4		$ 290.3
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	290.3
Real Estate [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Real Estate [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Real Estate [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		254.9	0	[3]	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		254.9
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
Transfers into Level 3		0
Transfers out of Level 3	[1]	(254.9)
Fair Value of Plan Assets as of December 31	[3]	0
Alternative Investments [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	446	$ 444.6		$ 446
Year End Allocation
Total	[3]		9.50%		8.60%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	446
Alternative Investments [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	446	$ 444.6		$ 446
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	446
Alternative Investments [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Alternative Investments [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Alternative Investments [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		411.1	0	[3]	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		411.1
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
Transfers into Level 3		0
Transfers out of Level 3	[1]	(411.1)
Fair Value of Plan Assets as of December 31	[3]	0
Trusted Owned Life Insurance [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		223.6	$ 203.8		$ 223.6
Year End Allocation
Total			13.30%		12.90%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		223.6
Trusted Owned Life Insurance [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Trusted Owned Life Insurance [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Trusted Owned Life Insurance [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		223.6	203.8		223.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		223.6
Trusted Owned Life Insurance [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
International Equities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		105.4	$ 49.4		$ 105.4
Year End Allocation
Total			3.20%		6.10%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		105.4
International Equities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
International Equities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
International Equities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		105.4	49.4		105.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		105.4
International Equities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
United States Bonds [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		118.2	$ 154.4		$ 118.2
Year End Allocation
Total			10.10%		6.80%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		118.2
United States Bonds [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	$ 0		$ 0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
United States Bonds [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
United States Bonds [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		118.2	154.4		118.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		118.2
United States Bonds [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31		0
Cash and Cash Equivalents [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	57.2	$ 47.8		$ 57.2
Year End Allocation
Total	[3]		1.00%		1.10%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	57.2
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	40.9	$ 59.2		$ 40.9
Year End Allocation
Total	[4]		3.90%		2.40%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	40.9
Cash and Cash Equivalents [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	21.2	$ 11.9		$ 21.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	21.2
Cash and Cash Equivalents [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	4.2	4.8		4.2
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	4.2
Cash and Cash Equivalents [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0.4	(0.4)		0.4
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0.4
Cash and Cash Equivalents [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	36.7	54.4		36.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	36.7
Cash and Cash Equivalents [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	35.6	36.3		35.6
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	35.6
Cash and Cash Equivalents [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Cash and Cash Equivalents [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[3]	0
Cash and Cash Equivalents [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0		0
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[4]	0
Other - Pending Transactions and Accrued Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	22.7	$ 8.3		$ 22.7
Year End Allocation
Total	[5]		0.20%		0.50%
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	22.7
Other - Pending Transactions and Accrued Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	(2.9)	$ (1.2)		$ (2.9)
Year End Allocation
Total	[6]		(0.10%)		(0.20%)
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	(2.9)
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	22.7	$ 8.3		$ 22.7
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	22.7
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	(2.9)	(1.2)		(2.9)
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	(2.9)
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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[5]	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
Actual Return on Plan Assets
Fair Value of Plan Assets as of December 31	[6]	$ 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]	Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
[3]	Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
[4]	Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
[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, 2018	Dec. 31, 2017	Dec. 31, 2016
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 71.8	$ 74.6	$ 72.9
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%
Multiemployer Plans Withdrawal Obligation	$ 15	$ 19
Noncurrent Regulatory Liabilities	8,540.3	8,422.3
Noncurrent Regulatory Assets	3,310.4	3,587.6
UMWA Withdrawal Obligation [Member]
Benefit Plans Textuals [Abstract]
Noncurrent Regulatory Liabilities	3
Noncurrent Regulatory Assets		1
AEP Texas Inc. [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5.7	6	5.2
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 Liabilities	$ 1,344.3	1,320.5
Noncurrent Regulatory Assets	430	378.7
Appalachian Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 7.5	7.4	7.3
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 Liabilities	$ 1,449.7	1,454.9
Noncurrent Regulatory Assets	475.8	573.9
Indiana Michigan Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 10.5	10.7	10.9
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 Liabilities	$ 1,574.5	1,708.7
Noncurrent Regulatory Assets	512.5	579.4
Ohio Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 6.3	6.1	5.6
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 Liabilities	$ 1,221.2	1,100.2
Noncurrent Regulatory Assets	387.5	652.8
Public Service Co Of Oklahoma [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 4.5	5	4.3
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 Liabilities	$ 864.7	853.5
Noncurrent Regulatory Assets	369	368.1
Southwestern Electric Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5.9	6	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 Liabilities	$ 923	896.4
Noncurrent Regulatory Assets	230.8	220.6
Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,625.6	5,025.2
Underfunded Benefit Obligation
Projected Benefit Obligation	4,810.3	5,215.8	5,085.8
Accumulated Benefit Obligation	4,625.6	5,025.2
Fair Value of Plan Assets	4,695.9	5,174.1	4,827.3
Underfunded Status, Projected Benefit Obligation	(114.4)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	98.7
Components of Net Periodic Benefit Cost
Service Cost	97.6	96.5	85.8
Interest Cost	187.8	203.1	211.6
Expected Return on Plan Assets	(290.3)	(284.8)	(280.3)
Amortization of Prior Service Cost (Credit)	0	1	2.3
Amortization of Net Actuarial Loss	85.2	82.8	83.8
Settlements	2.6	0	0
Net Periodic Benefit Cost (Credit)	82.9	98.6	103.2
Capitalized Portion	(41.1)	(39.9)	(37.8)
Net Periodic Benefit Cost (Credit) Recognized in Expense	41.8	58.7	65.4
Pension Plans [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	339.8
2,020	344.2
2,021	354.2
2,022	357.3
2,023	364.1
Years 2024 to 2028, in Total	1,808.2
Pension Plans [Member] | AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	396.8	425.2
Underfunded Benefit Obligation
Projected Benefit Obligation	409.3	441.3	421.7
Accumulated Benefit Obligation	396.8	425.2
Fair Value of Plan Assets	410.7	455.9	416.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	8
Components of Net Periodic Benefit Cost
Service Cost	9.2	8.6	7.5
Interest Cost	16	17.1	17.8
Expected Return on Plan Assets	(25.6)	(25)	(24.5)
Amortization of Prior Service Cost (Credit)	0	0	0.4
Amortization of Net Actuarial Loss	7.2	7	7.1
Net Periodic Benefit Cost (Credit)	6.8	7.7	8.3
Capitalized Portion	(4.8)	(4)	(3.6)
Net Periodic Benefit Cost (Credit) Recognized in Expense	2	3.7	4.7
Pension Plans [Member] | AEP Texas Inc. [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	30.8
2,020	34.3
2,021	34.9
2,022	33.5
2,023	34.9
Years 2024 to 2028, in Total	164.7
Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	588.5	648.2
Underfunded Benefit Obligation
Projected Benefit Obligation	603.1	665	654
Accumulated Benefit Obligation	588.5	648.2
Fair Value of Plan Assets	593.3	651.7	606.4
Underfunded Status, Projected Benefit Obligation	(9.8)	(13.3)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	7.7
Components of Net Periodic Benefit Cost
Service Cost	9.3	9.4	8.1
Interest Cost	23.5	25.7	27.2
Expected Return on Plan Assets	(36.6)	(35.8)	(35.3)
Amortization of Prior Service Cost (Credit)	0	0.2	0.1
Amortization of Net Actuarial Loss	10.6	10.4	10.8
Net Periodic Benefit Cost (Credit)	6.8	9.9	10.9
Capitalized Portion	(3.8)	(4)	(4.1)
Net Periodic Benefit Cost (Credit) Recognized in Expense	3	5.9	6.8
Pension Plans [Member] | Appalachian Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	43.4
2,020	42.8
2,021	43.4
2,022	43.6
2,023	44.2
Years 2024 to 2028, in Total	220.2
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	536.9	592.8
Underfunded Benefit Obligation
Projected Benefit Obligation	567	624.3	611.6
Accumulated Benefit Obligation	536.9	592.8
Fair Value of Plan Assets	583.8	636.7	586.1
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	1.1
Components of Net Periodic Benefit Cost
Service Cost	13.6	14	12.2
Interest Cost	22.1	24.3	25.3
Expected Return on Plan Assets	(35.7)	(34.6)	(33.6)
Amortization of Prior Service Cost (Credit)	0	0.2	0.1
Amortization of Net Actuarial Loss	9.8	9.7	10
Net Periodic Benefit Cost (Credit)	9.8	13.6	14
Capitalized Portion	(5.6)	(5.5)	(3.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	4.2	8.1	10.7
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	36.2
2,020	36.4
2,021	37.5
2,022	38.9
2,023	40.3
Years 2024 to 2028, in Total	210.6
Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	438.5	483.5
Underfunded Benefit Obligation
Projected Benefit Obligation	453.9	501.1	492.9
Accumulated Benefit Obligation	438.5	483.5
Fair Value of Plan Assets	466.1	509.1	473.8
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0.5
Components of Net Periodic Benefit Cost
Service Cost	7.7	7.5	6.5
Interest Cost	17.7	19.4	20.6
Expected Return on Plan Assets	(28.8)	(27.9)	(27.6)
Amortization of Prior Service Cost (Credit)	0	0.1	0.1
Amortization of Net Actuarial Loss	8	7.8	8.1
Net Periodic Benefit Cost (Credit)	4.6	6.9	7.7
Capitalized Portion	(3.6)	(3.3)	(3.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	1	3.6	4.3
Pension Plans [Member] | Ohio Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	34.3
2,020	34.5
2,021	34
2,022	33.9
2,023	34.7
Years 2024 to 2028, in Total	163.3
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	240.2	259.6
Underfunded Benefit Obligation
Projected Benefit Obligation	253.8	276.6	266.7
Accumulated Benefit Obligation	240.2	259.6
Fair Value of Plan Assets	261.2	287.8	266
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0.2
Components of Net Periodic Benefit Cost
Service Cost	7	6.4	6.2
Interest Cost	9.9	10.7	11.2
Expected Return on Plan Assets	(16.1)	(15.6)	(15.5)
Amortization of Prior Service Cost (Credit)	0	0	0.3
Amortization of Net Actuarial Loss	4.4	4.3	4.4
Net Periodic Benefit Cost (Credit)	5.2	5.8	6.6
Capitalized Portion	(2.6)	(2.1)	(2.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	2.6	3.7	4.2
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	19
2,020	19.5
2,021	21.2
2,022	20.4
2,023	23.1
Years 2024 to 2028, in Total	102.5
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	272.8	291.6
Underfunded Benefit Obligation
Projected Benefit Obligation	291.4	314.6	296.6
Accumulated Benefit Obligation	272.8	291.6
Fair Value of Plan Assets	281	311.7	287.3
Underfunded Status, Projected Benefit Obligation	(10.4)	(2.9)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	7.9
Components of Net Periodic Benefit Cost
Service Cost	9.3	8.7	8.1
Interest Cost	11.3	12.3	12.4
Expected Return on Plan Assets	(17.3)	(17)	(16.4)
Amortization of Prior Service Cost (Credit)	0	0.1	0.3
Amortization of Net Actuarial Loss	5.1	4.9	4.8
Settlements	0.4	0	0
Net Periodic Benefit Cost (Credit)	8.8	9	9.2
Capitalized Portion	(3.1)	(2.7)	(2.7)
Net Periodic Benefit Cost (Credit) Recognized in Expense	5.7	6.3	6.5
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	21.4
2,020	21.8
2,021	22.9
2,022	23.8
2,023	24
Years 2024 to 2028, in Total	120.5
Qualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,560.7	4,951.3
Underfunded Benefit Obligation
Accumulated Benefit Obligation	4,560.7	4,951.3
Qualified Pension Plans [Member] | AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	393.2	421.4
Underfunded Benefit Obligation
Accumulated Benefit Obligation	393.2	421.4
Qualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	588.3	648
Underfunded Benefit Obligation
Accumulated Benefit Obligation	588.3	648
Qualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	536.3	592.4
Underfunded Benefit Obligation
Accumulated Benefit Obligation	536.3	592.4
Qualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	438.3	483.4
Underfunded Benefit Obligation
Accumulated Benefit Obligation	438.3	483.4
Qualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	238	256.9
Underfunded Benefit Obligation
Accumulated Benefit Obligation	238	256.9
Qualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	271.6	289.4
Underfunded Benefit Obligation
Accumulated Benefit Obligation	271.6	289.4
Nonqualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	64.9	73.9
Underfunded Benefit Obligation
Projected Benefit Obligation		78
Accumulated Benefit Obligation	64.9	73.9
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation		(78)
Underfunded Status, Accumulated Benefit Obligation	(64.9)	(73.9)
Nonqualified Pension Plans [Member] | AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	3.6	3.8
Underfunded Benefit Obligation
Projected Benefit Obligation	3.8	4
Accumulated Benefit Obligation	3.6	3.8
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(3.8)	(4)
Underfunded Status, Accumulated Benefit Obligation	(3.6)	(3.8)
Nonqualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.2	0.2
Underfunded Benefit Obligation
Accumulated Benefit Obligation	0.2	0.2
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(0.2)	(0.2)
Nonqualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.6	0.4
Underfunded Benefit Obligation
Projected Benefit Obligation	1.2	1
Accumulated Benefit Obligation	0.6	0.4
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(1.2)	(1)
Underfunded Status, Accumulated Benefit Obligation	(0.6)	(0.4)
Nonqualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.2	0.1
Underfunded Benefit Obligation
Projected Benefit Obligation	0.4	0.4
Accumulated Benefit Obligation	0.2	0.1
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(0.4)	(0.4)
Underfunded Status, Accumulated Benefit Obligation	(0.2)	(0.1)
Nonqualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	2.2	2.7
Underfunded Benefit Obligation
Projected Benefit Obligation	2.3	2.7
Accumulated Benefit Obligation	2.2	2.7
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(2.3)	(2.7)
Underfunded Status, Accumulated Benefit Obligation	(2.2)	(2.7)
Nonqualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	1.2	2.2
Underfunded Benefit Obligation
Accumulated Benefit Obligation	1.2	2.2
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(1.2)	(2.2)
Other Postretirement Benefit Plans [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	1,194.5	1,332	1,447.4
Fair Value of Plan Assets	1,534.2	1,732.5	1,545.9
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	4.5
Components of Net Periodic Benefit Cost
Service Cost	11.6	11.2	10.2
Interest Cost	47.4	59.3	60.9
Expected Return on Plan Assets	(102.2)	(101.3)	(107)
Amortization of Prior Service Cost (Credit)	(69.1)	(69.1)	(69)
Amortization of Net Actuarial Loss	10.5	36.7	31.4
Settlements	0	0	0
Net Periodic Benefit Cost (Credit)	(101.8)	(63.2)	(73.5)
Capitalized Portion	(4.9)	25.6	26.9
Net Periodic Benefit Cost (Credit) Recognized in Expense	(106.7)	(37.6)	(46.6)
Other Postretirement Benefit Plans [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	122
2,020	126.5
2,021	127.1
2,022	127.2
2,023	126.3
Years 2024 to 2028, in Total	618.8
Other Postretirement Benefit Plans [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0.2
2,020	0.2
2,021	0.3
2,022	0.3
2,023	0.3
Years 2024 to 2028, in Total	1.5
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	95.9	107.1	120.4
Fair Value of Plan Assets	129.9	147.3	134.1
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0.1
Components of Net Periodic Benefit Cost
Service Cost	0.9	0.9	0.7
Interest Cost	3.8	4.9	5.1
Expected Return on Plan Assets	(8.6)	(8.8)	(9.3)
Amortization of Prior Service Cost (Credit)	(5.9)	(5.8)	(6)
Amortization of Net Actuarial Loss	0.8	3.2	2.8
Net Periodic Benefit Cost (Credit)	(9)	(5.6)	(6.7)
Capitalized Portion	(0.5)	2.9	3.4
Net Periodic Benefit Cost (Credit) Recognized in Expense	(9.5)	(2.7)	(3.3)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	10
2,020	10.5
2,021	10.7
2,022	10.9
2,023	10.9
Years 2024 to 2028, in Total	53.6
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0
2,020	0
2,021	0
2,022	0
2,023	0
Years 2024 to 2028, in Total	0
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	205.5	236.5	255.6
Fair Value of Plan Assets	238.4	273.4	246.9
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	2.1
Components of Net Periodic Benefit Cost
Service Cost	1.1	1.1	1
Interest Cost	8.2	10.6	10.8
Expected Return on Plan Assets	(16)	(16.5)	(17.3)
Amortization of Prior Service Cost (Credit)	(10)	(10.1)	(10.1)
Amortization of Net Actuarial Loss	1.9	6.3	5.4
Net Periodic Benefit Cost (Credit)	(14.8)	(8.6)	(10.2)
Capitalized Portion	(0.5)	3.5	3.9
Net Periodic Benefit Cost (Credit) Recognized in Expense	(15.3)	(5.1)	(6.3)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	22
2,020	22.5
2,021	22.2
2,022	22.1
2,023	21.6
Years 2024 to 2028, in Total	103.4
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0.2
2,020	0.2
2,021	0.2
2,022	0.2
2,023	0.2
Years 2024 to 2028, in Total	0.7
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	138.3	153.5	167.6
Fair Value of Plan Assets	187.3	211.1	186.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0
Components of Net Periodic Benefit Cost
Service Cost	1.6	1.6	1.5
Interest Cost	5.4	6.9	7
Expected Return on Plan Assets	(12.3)	(12.2)	(12.9)
Amortization of Prior Service Cost (Credit)	(9.5)	(9.4)	(9.4)
Amortization of Net Actuarial Loss	1.2	4.4	3.7
Net Periodic Benefit Cost (Credit)	(13.6)	(8.7)	(10.1)
Capitalized Portion	(0.7)	3.5	2.4
Net Periodic Benefit Cost (Credit) Recognized in Expense	(14.3)	(5.2)	(7.7)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	14.8
2,020	15.4
2,021	15.7
2,022	15.7
2,023	15.6
Years 2024 to 2028, in Total	75.6
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0
2,020	0
2,021	0
2,022	0
2,023	0
Years 2024 to 2028, in Total	0
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	129.5	144.3	164
Fair Value of Plan Assets	175.4	198.5	182.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	0.9	0.8
Interest Cost	5.1	6.7	7
Expected Return on Plan Assets	(11.7)	(11.9)	(13)
Amortization of Prior Service Cost (Credit)	(6.9)	(6.9)	(6.9)
Amortization of Net Actuarial Loss	1.1	4.3	3.8
Net Periodic Benefit Cost (Credit)	(11.5)	(6.9)	(8.3)
Capitalized Portion	(0.4)	3.3	3.7
Net Periodic Benefit Cost (Credit) Recognized in Expense	(11.9)	(3.6)	(4.6)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	14.5
2,020	14.8
2,021	14.8
2,022	14.7
2,023	14.5
Years 2024 to 2028, in Total	69.1
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0
2,020	0
2,021	0
2,022	0
2,023	0
Years 2024 to 2028, in Total	0
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	62.3	69.4	77.6
Fair Value of Plan Assets	84.3	95.5	86.4
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0
Components of Net Periodic Benefit Cost
Service Cost	0.7	0.7	0.6
Interest Cost	2.5	3.2	3.3
Expected Return on Plan Assets	(5.6)	(5.6)	(6.1)
Amortization of Prior Service Cost (Credit)	(4.3)	(4.3)	(4.3)
Amortization of Net Actuarial Loss	0.5	2	1.8
Net Periodic Benefit Cost (Credit)	(6.2)	(4)	(4.7)
Capitalized Portion	(0.3)	1.4	1.7
Net Periodic Benefit Cost (Credit) Recognized in Expense	(6.5)	(2.6)	(3)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	6.3
2,020	6.8
2,021	6.8
2,022	7
2,023	7.1
Years 2024 to 2028, in Total	34.9
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0
2,020	0
2,021	0
2,022	0
2,023	0
Years 2024 to 2028, in Total	0
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	72.7	80.3	86.9
Fair Value of Plan Assets	98.5	110.4	96.8
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2019	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	0.9	0.8
Interest Cost	2.8	3.6	3.6
Expected Return on Plan Assets	(6.4)	(6.3)	(6.8)
Amortization of Prior Service Cost (Credit)	(5.2)	(5.2)	(5)
Amortization of Net Actuarial Loss	0.6	2.3	1.9
Settlements	0	0	0
Net Periodic Benefit Cost (Credit)	(7.3)	(4.7)	(5.5)
Capitalized Portion	(0.3)	1.4	1.6
Net Periodic Benefit Cost (Credit) Recognized in Expense	(7.6)	$ (3.3)	$ (3.9)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,019	7.1
2,020	7.5
2,021	7.8
2,022	8
2,023	8.1
Years 2024 to 2028, in Total	41.5
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,019	0
2,020	0
2,021	0
2,022	0
2,023	0
Years 2024 to 2028, in Total	$ 0

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended													12 Months Ended
		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Reportable Segment Information
Revenue from Contracts with Customers															$ 16,195.7		$ 15,424.9		$ 16,380.1
Sales to AEP Affiliates															0		0		0
Total Revenues		$ 3,801.1		$ 4,333.1		$ 4,013.2		$ 4,048.3		$ 3,810.4		$ 4,104.7	$ 3,576.5	$ 3,933.3	16,195.7		15,424.9		16,380.1
Asset Impairments and Other Related Charges															70.6		87.1		2,267.8
Utilities Operating Expense, Depreciation and Amortization															2,286.6		1,997.2		1,962.3
Interest and Investment Income															11.6		16		16.3
Carrying Costs Income															6.6		18.6		16.2
Allowance for Equity Funds Used During Construction															132.5		93.7		113.2
Interest Expense															984.4		895		877.2
Income Tax Expense (Benefit)															115.3		969.7		(73.7)
Income from Continuing Operations															1,931.3		1,928.9		620.5
Income (Loss) from Discontinued Operations, Net of Tax															0		0		(2.5)
NET INCOME (LOSS)		364.8		579.7		530.1		456.7		401.8		556.7	376.2	594.2	1,931.3		1,928.9		618
Gross Property Additions															6,325.5		5,698.1		4,889
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		73,085.2								67,428.5					73,085.2		67,428.5
Accumulated Depreciation and Amortization		17,986.1								17,167					17,986.1		17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		55,099.1								50,261.5					55,099.1		50,261.5
Total Assets		68,802.8								64,729.1					68,802.8		64,729.1		63,467.7
Investments in Equity Method Investees		846.2								812.3					846.2		812.3
Long-term Debt Due Within One Year		1,698.5								1,753.7					1,698.5		1,753.7
Long-term Debt - Affiliated		0								0					0		0
Long-term Debt		21,648.2								19,419.6					21,648.2		19,419.6
Total Long-term Debt Outstanding		23,346.7								21,173.3					23,346.7		21,173.3
AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															832
Sales to AEP Affiliates															598.9		568.1	[1]	367.5
Total Revenues		189.9	[2]	194.4	[2]	200.1	[2]	191.7	[2]	159.2		165.6	229.4	152.7	776.1		706.9	[1]	478
Utilities Operating Expense, Depreciation and Amortization															133.9		95.7	[1],[3]	65.9
Interest Income															2.5		1.2	[1]	0.4
Allowance for Equity Funds Used During Construction															70.6		49	[1],[4]	52.3
Interest Expense															83.2		70.2	[1]	46
Income Tax Expense (Benefit)															84.1		142.2	[1],[5]	94.1
NET INCOME (LOSS)		71.7	[2]	$ 78.1	[2]	$ 82	[2]	$ 84.1	[2]	47.7		$ 58.6	$ 107.4	$ 57	315.9		270.7	[1],[5]	192.7
Gross Property Additions															1,570.8		1,522.5	[1]	1,166
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		8,268.1								6,770.5	[1]				8,268.1		6,770.5	[1]
Accumulated Depreciation and Amortization		271.9								152.6	[1]				271.9		152.6	[1]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,996.2								6,617.9	[1],[6]				7,996.2		6,617.9	[1],[6]
Notes Receivable, Related Parties		0								0	[1]				0		0	[1]
Total Assets		8,394.1								7,082.1	[1]				8,394.1		7,082.1	[1]	5,349.8
Long-term Debt Due Within One Year		85								50					85		50
Long-term Debt		2,738								2,500.4					2,738		2,500.4
Total Long-term Debt Outstanding		2,823								2,550.4	[1]				2,823		2,550.4	[1]
Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers															9,556.7		9,095.1		9,012.4
Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers															4,552.3		4,328.9		4,328.3
Transmission [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															177		138	[1]	110.4
Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers															1,818.1		1,771.4		2,858.7
Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers															268.6		229.5		180.7
Total Revenues	[7]														123
Other Revenues [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															0.2		0.8	[1]	0.1
Total Revenues	[8]														0
Reconciling Adjustments [Member]
Reportable Segment Information
Revenue from Contracts with Customers															0		0		0
Sales to AEP Affiliates															(942.4)		(949)		(738.1)
Total Revenues															(942.4)		(949)		(738.1)
Asset Impairments and Other Related Charges															0		0		0
Utilities Operating Expense, Depreciation and Amortization	[9]														57.1		60.5		16.7
Interest and Investment Income															(50.9)		(33.3)		(16.9)
Carrying Costs Income															0		0		(14)
Interest Expense	[9]														(59.7)		(44.3)		(28.4)
Income Tax Expense (Benefit)															0		0		0
Income from Continuing Operations																			0
Income (Loss) from Discontinued Operations, Net of Tax																			0
NET INCOME (LOSS)															0		0		0
Gross Property Additions															(39.2)		(90.4)		(18.1)
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)	[9]	(354.6)								(366.4)					(354.6)		(366.4)
Accumulated Depreciation and Amortization	[9]	(186.5)								(186.9)					(186.5)		(186.9)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[9]	(168.1)								(179.5)					(168.1)		(179.5)
Total Assets	[9],[10]	(2,714.8)								(3,022)					(2,714.8)		(3,022)		(2,417.3)
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)								(82.2)					(82.2)		(82.2)
Long-term Debt		0								0					0		0
Total Long-term Debt Outstanding		(82.2)								(82.2)					(82.2)		(82.2)
Reconciling Adjustments [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															0		0		0
Sales to AEP Affiliates															0		0		0
Total Revenues															0		0		0
Utilities Operating Expense, Depreciation and Amortization															0		0		0
Interest Income	[11]														(103.4)		(82.4)		(57.5)
Allowance for Equity Funds Used During Construction															0		0		0
Interest Expense	[11]														(103.4)		(82.4)		(57.5)
Income Tax Expense (Benefit)															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	[12]	(2,823)								(2,550.4)					(2,823)		(2,550.4)
Total Assets	[13]	(2,869.8)								(2,594.9)					(2,869.8)		(2,594.9)		(1,975.4)
Total Long-term Debt Outstanding	[12]	(2,850)								(2,575)					(2,850)		(2,575)
Reconciling Adjustments [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues	[7]														0
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates															88.8		96.9		79.5
Total Revenues															9,645.5		9,192		9,091.9
Asset Impairments and Other Related Charges															3.4		33.6		10.5
Utilities Operating Expense, Depreciation and Amortization															1,316.2		1,142.5		1,073.8
Interest and Investment Income															11.7		6.8		4.8
Carrying Costs Income															5.3		15.2		10.5
Interest Expense															567.8		540		522.1
Income Tax Expense (Benefit)															5.7		425.6		397.3
Income from Continuing Operations																			984
Income (Loss) from Discontinued Operations, Net of Tax																			0
NET INCOME (LOSS)															995.5		803.3		984
Gross Property Additions															2,282.2		2,343.2		2,237
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		45,365.1								43,294.4					45,365.1		43,294.4
Accumulated Depreciation and Amortization		13,822.5								13,153.4					13,822.5		13,153.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		31,542.6								30,141					31,542.6		30,141
Total Assets		38,874.3								37,579.7					38,874.3		37,579.7		37,428.3
Investments in Equity Method Investees		39.6								37.1					39.6		37.1
Long-term Debt Due Within One Year		1,066.3								1,038.1					1,066.3		1,038.1
Long-term Debt - Affiliated		50								50					50		50
Long-term Debt		11,442.7								10,801.4					11,442.7		10,801.4
Total Long-term Debt Outstanding		12,559								11,889.5					12,559		11,889.5
Vertically Integrated Utilities [Member] | Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers															9,556.7		9,095.1		9,012.4
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues	[7]														(10.5)
Transmission and Distribution Companies [Member]
Reportable Segment Information
Sales to AEP Affiliates															100.8		90.4		94.1
Total Revenues															4,653.1		4,419.3		4,422.4
Asset Impairments and Other Related Charges															0		0		0
Utilities Operating Expense, Depreciation and Amortization															734.1		667.5		649.9
Interest and Investment Income															4.2		7.7		14.8
Carrying Costs Income															1.7		3.6		20
Interest Expense															248.1		244.1		256.9
Income Tax Expense (Benefit)															42.4		127.2		205.1
Income from Continuing Operations																			482.1
Income (Loss) from Discontinued Operations, Net of Tax																			0
NET INCOME (LOSS)															527.4		636.4		482.1
Gross Property Additions															2,162.4		1,558.4		1,058.3
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		18,126.7								16,371.2					18,126.7		16,371.2
Accumulated Depreciation and Amortization		3,833.7								3,768.3					3,833.7		3,768.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		14,293								12,602.9					14,293		12,602.9
Total Assets		17,083.4								16,060.7					17,083.4		16,060.7		14,802.4
Investments in Equity Method Investees		2.9								1.5					2.9		1.5
Long-term Debt Due Within One Year		549.1								663.1					549.1		663.1
Long-term Debt - Affiliated		0								0					0		0
Long-term Debt		5,048.8								4,705.4					5,048.8		4,705.4
Total Long-term Debt Outstanding		5,597.9								5,368.5					5,597.9		5,368.5
Transmission and Distribution Companies [Member] | Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers															4,552.3		4,328.9		4,328.3
Transmission and Distribution Companies [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues	[7]														102.3
AEP Transmission Holdco
Reportable Segment Information
Sales to AEP Affiliates															555.5		588.3		366.9
Total Revenues															804.1		766.7		512.8
Asset Impairments and Other Related Charges															0		0		0
Utilities Operating Expense, Depreciation and Amortization															137.8		102.2		67.1
Interest and Investment Income															2.5		1.2		0.4
Carrying Costs Income															(0.4)		(0.2)		(0.3)
Interest Expense															90.7		72.8		50.3
Income Tax Expense (Benefit)															95.3		189.8		134.1
Income from Continuing Operations																			269.3
Income (Loss) from Discontinued Operations, Net of Tax																			0
NET INCOME (LOSS)															373		355.6		269.3
Gross Property Additions															1,614.1		1,542.8		1,265.8
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		8,659.5								7,110.2					8,659.5		7,110.2
Accumulated Depreciation and Amortization		282.8								176.6					282.8		176.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,376.7								6,933.6					8,376.7		6,933.6
Total Assets		9,543.7								8,141.8					9,543.7		8,141.8		6,384.8
Investments in Equity Method Investees		750.9								742.9					750.9		742.9
Long-term Debt Due Within One Year		85								50					85		50
Long-term Debt - Affiliated		0								0					0		0
Long-term Debt		2,888.6								2,631.3					2,888.6		2,631.3
Total Long-term Debt Outstanding		2,973.6								2,681.3					2,973.6		2,681.3
AEP Transmission Holdco | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers															248.6		178.4		145.9
Generation and Marketing [Member]
Reportable Segment Information
Sales to AEP Affiliates															122.2		103.7		127.3
Total Revenues															1,940.3		1,875.1		2,986
Asset Impairments and Other Related Charges															47.7		53.5		2,257.3
Utilities Operating Expense, Depreciation and Amortization															41		24.2		154.6
Interest and Investment Income															13.1		10.3		1.4
Carrying Costs Income															0		0		0
Interest Expense															14.9		18.5		35.8
Income Tax Expense (Benefit)															(49.2)		189.7		(666.5)
Income from Continuing Operations																			(1,198)
Income (Loss) from Discontinued Operations, Net of Tax																			0
NET INCOME (LOSS)															134.7		166		(1,198)
Gross Property Additions															289.7		328.5		336.2
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		893.3								644.6					893.3		644.6
Accumulated Depreciation and Amortization		47								75					47		75
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		846.3								569.6					846.3		569.6
Total Assets		1,979.7								2,009.8					1,979.7		2,009.8		3,386.1
Investments in Equity Method Investees		26.7								16.6					26.7		16.6
Long-term Debt Due Within One Year		0.1								0					0.1		0
Long-term Debt - Affiliated		32.2								32.2					32.2		32.2
Long-term Debt		(0.3)								(0.3)					(0.3)		(0.3)
Total Long-term Debt Outstanding		32								31.9					32		31.9
Generation and Marketing [Member] | Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers															1,818.1		1,771.4		2,858.7
Generation and Marketing [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues	[7]														22.3
All Other [Member]
Reportable Segment Information
Sales to AEP Affiliates	[14]														75.1		69.7		70.3
Total Revenues	[14]														95.1		120.8		105.1
Asset Impairments and Other Related Charges	[14]														19.5		0		0
Utilities Operating Expense, Depreciation and Amortization	[14]														0.4		0.3		0.2
Interest and Investment Income	[14]														31		23.3		11.8
Carrying Costs Income	[14]														0		0		0
Interest Expense	[14]														122.6		63.9		40.5
Income Tax Expense (Benefit)	[14]														21.1		37.4		(143.7)
Income from Continuing Operations																			83.1
Income (Loss) from Discontinued Operations, Net of Tax	[14]																		(2.5)
NET INCOME (LOSS)	[14]														(99.3)		(32.4)		80.6
Gross Property Additions	[14]														16.3		15.6		9.8
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)	[14]	395.2								374.5					395.2		374.5
Accumulated Depreciation and Amortization	[14]	186.6								180.6					186.6		180.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[14]	208.6								193.9					208.6		193.9
Total Assets	[14],[15]	4,036.5								3,959.1					4,036.5		3,959.1		3,883.4
Investments in Equity Method Investees	[14]	26.1								14.2					26.1		14.2
Long-term Debt Due Within One Year	[14]	(2)	[16]							2.5					(2)	[16]	2.5
Long-term Debt - Affiliated	[14]	0								0					0		0
Long-term Debt	[14]	2,268.4	[16]							1,281.8					2,268.4	[16]	1,281.8
Total Long-term Debt Outstanding	[14]	2,266.4								1,284.3					2,266.4		1,284.3
All Other [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers	[14]														20		51.1		34.8
Total Revenues	[7]														8.9
State Transcos [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates															598.9		568.1	[1]	367.5
Total Revenues															776.1		706.9	[1]	478
Utilities Operating Expense, Depreciation and Amortization															133.9		95.7	[1]	65.9
Interest Income															1.3		0.7	[1]	0.1
Allowance for Equity Funds Used During Construction															70.6		49	[1]	52.3
Interest Expense															83.2		70.2	[1]	45.6
Income Tax Expense (Benefit)															83.9		142	[1]	94.4
NET INCOME (LOSS)															314.9		270.4	[1]	193.3
Gross Property Additions															1,570.8		1,522.5	[1]	1,166
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		8,268.1								6,770.5	[1]				8,268.1		6,770.5	[1]
Accumulated Depreciation and Amortization		271.9								152.6	[1]				271.9		152.6	[1]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,996.2								6,617.9	[1]				7,996.2		6,617.9	[1]
Notes Receivable, Related Parties		0								0	[1]				0		0	[1]
Total Assets		8,406.8								7,086.9	[1]				8,406.8		7,086.9	[1]	5,337.5
Total Long-term Debt Outstanding		2,850								2,575	[1]				2,850		2,575	[1]
State Transcos [Member] | Transmission [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															177		138	[1]	110.4
State Transcos [Member] | Other Revenues [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															0.2		0.8	[1]	0.1
AEPTCo Parent [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates															0		0		0
Total Revenues															0		0		0
Utilities Operating Expense, Depreciation and Amortization															0		0		0
Interest Income															104.6		82.9		57.8
Allowance for Equity Funds Used During Construction															0		0		0
Interest Expense															103.4		82.4		57.9
Income Tax Expense (Benefit)															0.2		0.2		(0.3)
NET INCOME (LOSS)	[17]														1		0.3		(0.6)
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		2,823								2,550.4					2,823		2,550.4
Total Assets	[18]	2,857.1								2,590.1					2,857.1		2,590.1		1,987.7
Total Long-term Debt Outstanding		$ 2,823								$ 2,550.4					2,823		2,550.4
AEPTCo Parent [Member] | Transmission [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															0		0		0
AEPTCo Parent [Member] | Other Revenues [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers															$ 0		$ 0		$ 0
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[2]	The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1.
[3]	(a)Reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see “Revisions to Previously Issued Financial Statements” below.
[4]	The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[5]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[6]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[7]	Amounts include affiliated and nonaffiliated revenues.
[8]	Amounts include affiliated and nonaffiliated revenues.
[9]	Includes eliminations due to an intercompany capital lease.
[10]	Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable
[11]	Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
[12]	Elimination of intercompany debt.
[13]	Primarily relates to elimination of Notes Receivable from the State Transcos.
[14]	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 other nonallocated costs.
[15]	Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
[16]	Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.
[17]	Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.
[18]	Includes elimination of AEPTCo Parent’s investments in 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, 2018USD ($)MWhMMBTUgal		Dec. 31, 2017USD ($)MWhMMBTUTgal		Dec. 31, 2016USD ($)
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 18,000,000		$ 9,400,000
Cash Collateral Paid Netted Against Risk Management Liabilities		4,000,000		9,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		162,800,000		126,200,000
Long-term Risk Management Assets		254,000,000		282,100,000
Total Assets		416,800,000		408,300,000
Current Risk Management Liabilities		55,000,000		61,600,000
Long-term Risk Management Liabilities		263,400,000		322,000,000
Total Liabilities		318,400,000		383,600,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		291,300,000		136,000,000		$ 28,400,000
Impact of Fair Value Hedges on the Balance Sheet
Carrying Amount of Hedged Asset (Liability)	[1]	(478,300,000)		(489,300,000)
Cumulative Fair Value Hedging Adjustment in the Carrying Amount of the Hedged Asset (Liability)	[1]	17,400,000		6,100,000
Impact of Cash Flow Hedges on the Balance Sheet
Gain (Loss) on Fair Value Hedging Instruments	[2]	(11,300,000)		(4,800,000)		1,600,000
Gain (Loss) on Fair Value Portion of Long Term Debt	[2]	11,300,000		4,800,000		(1,600,000)
Collateral Triggering Events
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		225,500,000		243,600,000
Amount of Cash Collateral Posted		1,800,000		1,300,000
Additional Settlement Liability if Cross Default Provision is Triggered		$ 181,000,000		223,100,000
Derivatives and Hedging (Textuals)
Maximum Length of Time Hedged in Price Risk Cash Flow Hedge		180 months
AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		$ 0		500,000
Current Risk Management Liabilities		200,000		0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(400,000)		400,000		400,000
Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		57,200,000		24,900,000
Long-term Risk Management Assets		900,000		1,100,000
Current Risk Management Liabilities		400,000		1,300,000
Long-term Risk Management Liabilities		200,000		200,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		141,100,000		43,200,000		56,500,000
Collateral Triggering Events
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		900,000		600,000
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		500,000
Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		8,600,000		7,600,000
Long-term Risk Management Assets		600,000		700,000
Current Risk Management Liabilities		300,000		3,500,000
Long-term Risk Management Liabilities		100,000		100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		11,700,000		14,600,000		27,000,000
Collateral Triggering Events
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		500,000		400,000
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		400,000
Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		0		600,000
Current Risk Management Liabilities		5,800,000		6,400,000
Long-term Risk Management Liabilities		93,800,000		126,000,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		25,600,000		(21,800,000)		(143,500,000)
Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		10,400,000		6,400,000
Current Risk Management Liabilities		1,000,000		0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		36,600,000		25,000,000		6,600,000
Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		4,800,000		6,400,000
Current Risk Management Liabilities		400,000		200,000
Long-term Risk Management Liabilities		2,200,000		0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		11,200,000		24,900,000		20,400,000
Collateral Triggering Events
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		2,300,000		200,000
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		2,300,000		100,000
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[3]	382,700,000	[4]	383,800,000	[5]
Total Liabilities	[3]	242,100,000	[4]	309,500,000	[5]
Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Total Assets	[3]			500,000
Total Liabilities	[3]	200,000
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	58,100,000		26,000,000
Total Liabilities	[3],[6]	600,000		1,500,000
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	9,200,000		8,300,000
Total Liabilities	[3],[6]	400,000		3,600,000
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]			600,000
Total Liabilities	[3],[6]	99,600,000		132,400,000
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	10,400,000		6,400,000
Total Liabilities	[3],[6]	1,000,000		0
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	4,800,000		6,400,000
Total Liabilities	[3],[6]	2,600,000		200,000
Commodity [Member]
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(23,000,000)		(28,400,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		10,400,000		5,500,000
Derivatives and Hedging (Textuals)
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	[7]	397,500,000		389,000,000
Long-term Risk Management Assets	[7]	276,400,000		300,900,000
Total Assets	[7]	673,900,000		689,900,000
Current Risk Management Liabilities	[7]	293,800,000		334,600,000
Long-term Risk Management Liabilities	[7]	225,700,000		280,600,000
Total Liabilities	[7]	519,500,000		615,200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	154,400,000		74,700,000
Commodity [Member] | Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0		500,000
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0		500,000
Current Risk Management Liabilities	[7]	700,000		0
Long-term Risk Management Liabilities	[7]	0		0
Total Liabilities	[7]	700,000		0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(700,000)		500,000
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	114,400,000		75,600,000
Long-term Risk Management Assets	[7]	3,100,000		2,400,000
Total Assets	[7]	117,500,000		78,000,000
Current Risk Management Liabilities	[7]	56,700,000		50,600,000
Long-term Risk Management Liabilities	[7]	2,400,000		1,400,000
Total Liabilities	[7]	59,100,000		52,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	58,400,000		26,000,000
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	50,400,000		47,200,000
Long-term Risk Management Assets	[7]	2,000,000		1,600,000
Total Assets	[7]	52,400,000		48,800,000
Current Risk Management Liabilities	[7]	41,100,000		48,500,000
Long-term Risk Management Liabilities	[7]	1,600,000		900,000
Total Liabilities	[7]	42,700,000		49,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	9,700,000		(600,000)
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0		600,000
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0		600,000
Current Risk Management Liabilities	[7]	6,400,000		6,400,000
Long-term Risk Management Liabilities	[7]	93,800,000		126,000,000
Total Liabilities	[7]	100,200,000		132,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(100,200,000)		(131,800,000)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	10,900,000		6,600,000
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	10,900,000		6,600,000
Current Risk Management Liabilities	[7]	1,700,000		200,000
Long-term Risk Management Liabilities	[7]	0		0
Total Liabilities	[7]	1,700,000		200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	9,200,000		6,400,000
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	5,600,000		7,000,000
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	5,600,000		7,000,000
Current Risk Management Liabilities	[7]	1,500,000		800,000
Long-term Risk Management Liabilities	[7]	2,200,000		0
Total Liabilities	[7]	3,700,000		800,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	1,900,000		6,200,000
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	28,500,000		17,500,000
Long-term Risk Management Assets	[7]	16,000,000		6,300,000
Total Assets	[7]	44,500,000		23,800,000
Current Risk Management Liabilities	[7]	13,200,000		9,000,000
Long-term Risk Management Liabilities	[7]	56,100,000		58,300,000
Total Liabilities	[7]	69,300,000		67,300,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(24,800,000)		(43,500,000)
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
AOCI Gain (Loss) Net of Tax		(12,600,000)		(13,000,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,100,000)		(800,000)
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		(4,400,000)		(4,500,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,100,000)		(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		1,800,000		2,200,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		900,000		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		(11,500,000)		(10,700,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,600,000)		(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		1,000,000		1,900,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		1,000,000		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		2,100,000		2,600,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		1,000,000		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		(3,300,000)		(6,000,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,500,000)		(1,400,000)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0		2,500,000
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0		2,500,000
Current Risk Management Liabilities	[7]	2,000,000		0
Long-term Risk Management Liabilities	[7]	15,400,000		8,600,000
Total Liabilities	[7]	17,400,000		8,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(17,400,000)		(6,100,000)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		426,000,000		409,000,000
Long-term Risk Management Assets		292,400,000		307,200,000
Total Assets		718,400,000		716,200,000
Current Risk Management Liabilities		309,000,000		343,600,000
Long-term Risk Management Liabilities		297,200,000		347,500,000
Total Liabilities		606,200,000		691,100,000
Total MTM Derivative Contract Net Assets (Liabilities)		112,200,000		25,100,000
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(263,200,000)		(282,800,000)
Long-term Risk Management Assets	[8]	(38,400,000)		(25,100,000)
Total Assets	[8]	(301,600,000)		(307,900,000)
Current Risk Management Liabilities	[8]	(254,000,000)		(282,000,000)
Long-term Risk Management Liabilities	[8]	(33,800,000)		(25,500,000)
Total Liabilities	[8]	(287,800,000)		(307,500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(13,800,000)		(400,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	(500,000)		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	(500,000)		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	500,000		0
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(57,200,000)		(50,700,000)
Long-term Risk Management Assets	[8]	(2,200,000)		(1,300,000)
Total Assets	[8]	(59,400,000)		(52,000,000)
Current Risk Management Liabilities	[8]	(56,300,000)		(49,300,000)
Long-term Risk Management Liabilities	[8]	(2,200,000)		(1,200,000)
Total Liabilities	[8]	(58,500,000)		(50,500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(900,000)		(1,500,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(41,800,000)		(39,600,000)
Long-term Risk Management Assets	[8]	(1,400,000)		(900,000)
Total Assets	[8]	(43,200,000)		(40,500,000)
Current Risk Management Liabilities	[8]	(40,800,000)		(45,000,000)
Long-term Risk Management Liabilities	[8]	(1,500,000)		(800,000)
Total Liabilities	[8]	(42,300,000)		(45,800,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(900,000)		5,300,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	(600,000)		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	(600,000)		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	600,000		0
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(500,000)		(200,000)
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	(500,000)		(200,000)
Current Risk Management Liabilities	[8]	(700,000)		(200,000)
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	(700,000)		(200,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	200,000		0
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(800,000)		(600,000)
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	(800,000)		(600,000)
Current Risk Management Liabilities	[8]	(1,100,000)		(600,000)
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	(1,100,000)		(600,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	300,000		0
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	162,800,000		126,200,000
Long-term Risk Management Assets	[9]	254,000,000		282,100,000
Total Assets	[9]	416,800,000		408,300,000
Current Risk Management Liabilities	[9]	55,000,000		61,600,000
Long-term Risk Management Liabilities	[9]	263,400,000		322,000,000
Total Liabilities	[9]	318,400,000		383,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	98,400,000		24,700,000
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	[9]	0		500,000
Long-term Risk Management Assets	[9]	0		0
Total Assets	[9]	0		500,000
Current Risk Management Liabilities	[9]	200,000		0
Long-term Risk Management Liabilities	[9]	0		0
Total Liabilities	[9]	200,000		0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(200,000)		500,000
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	[9]	57,200,000		24,900,000
Long-term Risk Management Assets	[9]	900,000		1,100,000
Total Assets	[9]	58,100,000		26,000,000
Current Risk Management Liabilities	[9]	400,000		1,300,000
Long-term Risk Management Liabilities	[9]	200,000		200,000
Total Liabilities	[9]	600,000		1,500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	57,500,000		24,500,000
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	[9]	8,600,000		7,600,000
Long-term Risk Management Assets	[9]	600,000		700,000
Total Assets	[9]	9,200,000		8,300,000
Current Risk Management Liabilities	[9]	300,000		3,500,000
Long-term Risk Management Liabilities	[9]	100,000		100,000
Total Liabilities	[9]	400,000		3,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	8,800,000		4,700,000
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	[9]	0		600,000
Long-term Risk Management Assets	[9]	0		0
Total Assets	[9]	0		600,000
Current Risk Management Liabilities	[9]	5,800,000		6,400,000
Long-term Risk Management Liabilities	[9]	93,800,000		126,000,000
Total Liabilities	[9]	99,600,000		132,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(99,600,000)		(131,800,000)
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	[9]	10,400,000		6,400,000
Long-term Risk Management Assets	[9]	0		0
Total Assets	[9]	10,400,000		6,400,000
Current Risk Management Liabilities	[9]	1,000,000		0
Long-term Risk Management Liabilities	[9]	0		0
Total Liabilities	[9]	1,000,000		0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	9,400,000		6,400,000
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	[9]	4,800,000		6,400,000
Long-term Risk Management Assets	[9]	0		0
Total Assets	[9]	4,800,000		6,400,000
Current Risk Management Liabilities	[9]	400,000		200,000
Long-term Risk Management Liabilities	[9]	2,200,000		0
Total Liabilities	[9]	2,600,000		200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	$ 2,200,000		$ 6,200,000
Power [Member]
Commodity
Derivative, Energy Notional Amount | MWh		371.1		358.7
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		66.4		57.4
Power [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		40.9		38.5
Power [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		7.8		10.4
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MWh		15.2		10.3
Power [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		4.5		22.7
Coal [Member]
Commodity
Derivative, Mass Notional Amount | T				2
Coal [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Mass Notional Amount | T				0
Coal [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T				0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T				2
Coal [Member] | Ohio Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T				0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Mass Notional Amount | T				0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T				0
Natural Gas [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		87.9		53.7
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		4		1.1
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		2.3		0.7
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		15.2		18.3
Heating Oil and Gasoline [Member]
Commodity
Derivative, Volume Notional Amount | gal		7.4		6.9
Heating Oil and Gasoline [Member] | AEP Texas Inc. [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.5		1.4
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.4		1.3
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		1.8		1.6
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.7		0.7
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.8		0.8
Interest Rate Contract [Member]
Commodity
Derivative, Notional Amount		$ 37,700,000		$ 50,700,000
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		0
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
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		(10,400,000)		6,100,000		4,000,000
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
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
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
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
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
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
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
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		38,900,000		42,800,000		59,400,000
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		(1,900,000)		600,000		(600,000)
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		(8,200,000)		5,300,000		4,100,000
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		0		100,000
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		100,000		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
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
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
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
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
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
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
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		8,600,000		5,600,000		6,600,000
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		7,600,000		2,000,000		3,500,000
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		800,000		600,000		300,000
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		1,700,000		800,000		(1,600,000)
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		400,000		100,000		(400,000)
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		200,000		100,000		(100,000)
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		200,000		100,000		(100,000)
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		300,000		100,000		(300,000)
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		200,000		100,000		(100,000)
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		200,000		100,000		(300,000)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,900,000		700,000		(1,800,000)
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		400,000		200,000		(400,000)
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		400,000		100,000		(400,000)
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		200,000		100,000		(100,000)
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		400,000		100,000		(400,000)
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		200,000		100,000		(200,000)
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		200,000		100,000		(200,000)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	27,900,000		(29,400,000)		(117,400,000)
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	[10]	(700,000)		0		800,000
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	[10]	(700,000)		0		600,000
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	[10]	7,100,000		(7,400,000)		3,100,000
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	[10]	24,900,000		(22,000,000)		(127,700,000)
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(1,100,000)		0		400,000
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	[10]	(1,200,000)		300,000		5,200,000
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	222,700,000		109,400,000		79,100,000
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	[10]	(500,000)		100,000		400,000
Regulatory Liabilities [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	135,500,000		40,400,000		51,400,000
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	[10]	11,600,000		15,900,000		13,900,000
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	[10]	0		0		(15,200,000)
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	[10]	37,300,000		24,800,000		6,500,000
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	[10]	$ 11,900,000		$ 24,300,000		$ 15,700,000
[1]	Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
[2]	Gain (Loss) is included in Interest Expense on the statements of income.
[3]	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.”
[4]	The December 31, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(4) million in 2019, $1 million in periods 2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $108 million in 2019, $37 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032. Risk management commodity contracts are substantially comprised of power contracts.
[5]	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 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.
[6]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[7]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[9]	All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
[10]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 23,346.7		$ 21,173.3
Long-term Debt, Fair Value		24,093.9		23,649.6
Other Temporary Investments
Cost		355		341.4
Gross Unrealized Gains		16.4		19.7
Gross Unrealized Losses		(2.3)		(1.4)
Fair Value		369.1		359.7
Debt and Equity Securities Within Other Temporary Investments
Proceeds From Investment Sales		0		0		$ 0
Purchases of Investments		3.1		14.2		2.3
Gross Realized Gains on Investment Sales		0		0		0
Gross Realized Losses on Investment Sales		0		0		0
Nuclear Trust Fund Investments
Fair Value		2,474.9		2,527.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,474.9		2,527.6
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		24,093.9		23,649.6
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		794.7		902.5
Other-Than-Temporary Impairments		(9.2)		(80.5)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,010		2,256.3		2,957.7
Purchases of Investments		2,064.7		2,300.5		3,000
Gross Realized Gains on Investment Sales		47.5		200.7		46.1
Gross Realized Losses on Investment Sales		32.8		146		24.4
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		359.4
After 1 year through 5 years		358.9
After 5 years through 10 years		176.1
After 10 years		162.7
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000		1,000
Adjusted Cost of Domestic Equity Securities		629		594
AEP Texas Inc. [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,881.3		3,649.3
Long-term Debt, Fair Value		3,964.6		3,964.8
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		3,964.6		3,964.8
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,823		2,550.4	[1]
Long-term Debt, Fair Value		2,782.4		2,782.9
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		2,782.4		2,782.9
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,062.6		3,980.1
Long-term Debt, Fair Value		4,473.3		4,782.6
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		4,473.3		4,782.6
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,035.4		2,745.1
Long-term Debt, Fair Value		3,070.2		3,014.7
Nuclear Trust Fund Investments
Fair Value		2,474.9		2,527.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,474.9		2,527.6
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		3,070.2		3,014.7
Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		794.7		902.5
Other-Than-Temporary Impairments		(9.2)		(80.5)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,010		2,256.3		2,957.7
Purchases of Investments		2,064.7		2,300.5		3,000
Gross Realized Gains on Investment Sales		47.5		200.7		46.1
Gross Realized Losses on Investment Sales		32.8		146		$ 24.4
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		359.4
After 1 year through 5 years		358.9
After 5 years through 10 years		176.1
After 10 years		162.7
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000		1,000
Adjusted Cost of Domestic Equity Securities		629		594
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,716.6		1,719.3
Long-term Debt, Fair Value		1,919.7		2,064.3
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		1,919.7		2,064.3
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,287		1,286.5
Long-term Debt, Fair Value		1,361.9		1,457.1
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		1,361.9		1,457.1
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,713.4		2,441.9
Long-term Debt, Fair Value		2,670.2		2,645.9
Fair Value Measurements (Textuals)
Long-term Debt, Fair Value		2,670.2		2,645.9
Cash [Member]
Other Temporary Investments
Cost	[2]	230.6		220.1
Gross Unrealized Gains	[2]	0		0
Gross Unrealized Losses	[2]	0		0
Fair Value	[2],[3]	230.6		220.1
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,057.1		1,048.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,057.1		1,048.7
Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		28.4		34.3
Other-Than-Temporary Impairments		(9.2)		(5)
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		1,057.1		1,048.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,057.1		1,048.7
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		28.4		34.3
Other-Than-Temporary Impairments		(9.2)		(5)
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[4]	106.6		104.3
Gross Unrealized Gains	[4]	0		0
Gross Unrealized Losses	[4]	(2.3)		(1.4)
Fair Value	[4]	104.3		102.9
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,395.3		1,461.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,395.3		1,461.7
Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities		784
Unrealized Loss on Securities		18
Nuclear Trust Fund Investments
Gross Unrealized Gains		766.3	[6]	868.2
Other-Than-Temporary Impairments		0	[6]	(75.5)
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,395.3		1,461.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,395.3		1,461.7
Domestic [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities		784
Unrealized Loss on Securities		18
Nuclear Trust Fund Investments
Gross Unrealized Gains		766.3	[6]	868.2
Other-Than-Temporary Impairments		0	[6]	(75.5)
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		17.8		17
Gross Unrealized Gains		16.4		19.7
Gross Unrealized Losses		0		0
Fair Value		34.2		36.7
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	22.5		17.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	22.5		17.2
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]	22.5		17.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	22.5		17.2
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		996.1		981.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		996.1		981.2
US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		26.7		29.7
Other-Than-Temporary Impairments		(7.1)		(3.6)
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		996.1		981.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		996.1		981.2
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		26.7		29.7
Other-Than-Temporary Impairments		(7.1)		(3.6)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		52.4		58.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		52.4		58.7
Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		1.1		3.8
Other-Than-Temporary Impairments		(1.9)		(1.2)
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		52.4		58.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		52.4		58.7
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		1.1		3.8
Other-Than-Temporary Impairments		(1.9)		(1.2)
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		8.6		8.8
Contractual Maturities, Fair Value of Debt Securities
Fair Value		8.6		8.8
State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.6		0.8
Other-Than-Temporary Impairments		(0.2)		(0.2)
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		8.6		8.8
Contractual Maturities, Fair Value of Debt Securities
Fair Value		8.6		8.8
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.6		0.8
Other-Than-Temporary Impairments		$ (0.2)		$ (0.2)
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[2]	Primarily represents amounts held for the repayment of debt.
[3]	Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[4]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[5]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[6]	Amount reported as Gross Unrealized Gains includes unrealized gains of $784 million and unrealized losses of $18 million. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.
[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, 2018USD ($)$ / MWh		Dec. 31, 2017USD ($)$ / MWh		Dec. 31, 2016USD ($)
Assets, Fair Value Disclosure
Other Temporary Investments		$ 369.1		$ 359.7
Risk Management Assets
Risk Management Assets		416.8		408.3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,474.9		2,527.6
Total Assets		3,260.8		3,295.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities		318.4		383.6
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		40.3		2.5		$ 146.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	148.9		37.3		42.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	9.8		33.6		26.1
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		15.7		(18.8)		(23)
Settlements		(214)		(50.6)		(71.4)
Transfers into Level 3	[3],[4]	15.8		16.2		13.3
Transfers out of Level 3	[4]	(1.6)		(10.1)		(2.6)
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	116.3		30.2		(129.6)
Ending Balance		131.2		40.3		2.5
Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		9.1		36.9
Risk Management Assets
Risk Management Assets		(291.2)		(285.4)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		10.2		9.7
Total Assets		(271.9)		(238.8)
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(277.4)		(285)
Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		360		322.8
Risk Management Assets
Risk Management Assets		3.8		3.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,407.6		1,469.2
Total Assets		1,771.4		1,795.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		4.2		5.1
Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Risk Management Assets
Risk Management Assets		350.6		411
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,057.1		1,048.7
Total Assets		1,407.7		1,459.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		369.2		425
Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Risk Management Assets
Risk Management Assets		353.6		278.8
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		353.6		278.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		222.4		238.5
2018 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				(1)
2018 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				(3)
2018 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				59
2019 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(4)
2019 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		108
2019 - 2021 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				33
2020 - 2022 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1
2020 - 2022 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		37
2022 - 2023 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
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)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				14
2023 - 2024 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1
2023 - 2024 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		23
2024 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				(29)
2025 - 2032 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1
2025 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(12)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6]	382.7	[7]	383.8	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	242.1	[7]	309.5	[8]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6]	(288.5)	[7]	(285.4)	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	(274.7)	[7]	(285)	[8]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6]	3.8	[7]	3.9	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	4.2	[7]	5.1	[8]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6]	326.5	[7]	391.2	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	327	[7]	392.5	[8]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6]	340.9	[7]	274.1	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	185.6	[7]	196.9	[8]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		257.1		225.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 212.5		$ 233.7
Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	(0.05)		(0.05)
Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	176.57		263
Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	33.07		36.32
Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 0		$ 0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 2.5		$ 0.2
Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	2.18		2.37
Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	3.54		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	[10]	2.47		2.62
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 96.5		$ 53.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 7.4		$ 4.6
FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	(11.68)		(55.62)
FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	17.79		54.88
FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	1.09		0.41
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[6]	$ 34.1		$ 22
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	58.9		65.5
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6]	(2.7)		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	(2.7)		0
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0		0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6]	24.1		17.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	24.8		23.9
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6]	12.7		4.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	36.8		41.6
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets				2.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		17.4		8.6
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		17.4		8.6
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
Cash and Cash Equivalents		156.7		155.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				155.7
AEP Texas Inc. [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0
AEP Texas Inc. [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		156.7		155.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				155.2
AEP Texas Inc. [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0.5
AEP Texas Inc. [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6]			0.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0.2
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6]			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	(0.5)
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6]			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6]			0.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0.7
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6]			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		25.6		16.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		83.7		42.3
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		24.7		1.4	[11]	11.7	[11]
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	104.1		17.2		25.6	[11]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0	[11]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0	[11]
Settlements		(127.9)		(18.9)		(37.5)	[11]
Transfers into Level 3	[3],[4]	0		0		0	[11]
Transfers out of Level 3	[4]	0		0		0.1	[11]
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	56.9		25		1.5	[11]
Ending Balance		57.8		24.7		1.4	[11]
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(59.4)		(51.6)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		25.6		16.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		25.7		16.3
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		59.1		52.5
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Risk Management Assets
Risk Management Assets		58.3		25.1
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		58.3		25.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.5		0.4
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	58.1		26
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.6		1.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	(59.4)		(51.6)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	(58.5)		(50.1)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	0.1		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.2		0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	59.1		52.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	58.4		51.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	58.3		25.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.5		0.4
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2.4		0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.5		$ 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	[9]	16.82		20.52
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	[9]	62.65		195
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	[9]	37		33.80
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 55.9		$ 24.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0		$ 0
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	0.10		(0.36)
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[9]	15.16		7.15
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	[9]	3.27		1.62
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,474.9		$ 2,527.6
Total Assets		2,484.1		2,535.9
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		7.6		2.8	[11]	4.3	[11]
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	14.2		4		7.1	[11]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0	[11]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0	[11]
Settlements		(21.3)		(7.1)		(11.1)	[11]
Transfers into Level 3	[3],[4]	0		0		0	[11]
Transfers out of Level 3	[4]	(0.3)		0		0.1	[11]
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	8.7		7.9		2.4	[11]
Ending Balance		8.9		7.6		2.8	[11]
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		10.2		9.7
Total Assets		(33)		(30.5)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,407.6		1,469.2
Total Assets		1,407.6		1,469.2
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,057.1		1,048.7
Total Assets		1,099.2		1,088.1
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		10.3		9.1
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		10.3		9.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.4		1.5
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	9.2		8.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.4		3.6
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	(43.2)		(40.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	(42.3)		(45.5)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.1		0
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	42.1		39.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	41.2		47.6
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	10.3		9.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	1.4		1.5
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1.4		0.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.9		$ 0.3
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	[9]	16.82		20.52
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	[9]	62.65		195
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	[9]	37		33.80
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 8.9		$ 8.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.5		$ 1.2
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	[9]	(2.11)		(0.36)
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	[9]	6.21		5.75
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	[9]	1.06		0.86
Ohio Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		$ 27.6
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		(132.4)		$ (119)		15.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	1.8		(1.4)		(3)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		4.6		7.4		6.2
Transfers into Level 3	[3],[4]	0		0		0
Transfers out of Level 3	[4]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	26.6		(19.4)		(138.1)
Ending Balance		(99.4)		(132.4)		(119)
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		27.6
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[12]			0.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	99.6		132.4
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[12]			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	(0.6)		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]			0.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.8		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	99.4		132.4
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		$ 99.4		$ 132.4
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	[9]	26.29		30.52
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	[9]	62.74		170.43
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	[9]	42.50		44.62
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		$ 6.2		$ 0.7		0.6
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	18.1		3.1		(1)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		(24.3)		(3.8)		0.4
Transfers into Level 3	[3],[4]	0		0		0
Transfers out of Level 3	[4]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	9.5		6.2		0.7
Ending Balance		9.5		6.2		0.7
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	10.4		6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	1		0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	(0.4)		(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	(0.6)		(0.2)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0		0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	0		0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.3		0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	10.8		6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	1.3		0.2
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		10.8		6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 1.3		$ 0.2
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	[9]	(11.68)		(6.62)
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	[9]	10.30		1.41
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	[9]	(1.40)		(0.76)
Southwestern Electric Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		$ 5.9		$ 0.7		0.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	(4.8)		6		7.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		(2.1)		(6.8)		(8.4)
Transfers into Level 3	[3],[4]	0		0		0
Transfers out of Level 3	[4]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	3.3		6		0.6
Ending Balance		2.3		5.9		$ 0.7
Southwestern Electric Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		5.6		6.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		3.3		0.8
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	4.8		6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	2.6		0.2
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	(0.8)		(0.6)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	(1.1)		(0.6)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0		0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	0		0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	0.4		0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[12]	5.6		6.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[12]	3.3		0.8
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 2.5		$ 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	[10]	2.18		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	[10]	3.54		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	[10]	2.47		2.62
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 5.6		$ 6.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.8		$ 0.6
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	[9]	(11.68)		(6.62)
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	[9]	10.30		1.41
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	[9]	(1.40)		(0.76)
Cash [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[13],[14]	$ 230.6		$ 220.1
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[13]	9.1		36.9
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[13]	221.5		183.2
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[13]	0		0
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[13]	0		0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,057.1		1,048.7
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		1,057.1		1,048.7
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		1,057.1		1,048.7
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		1,057.1		1,048.7
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
Other Temporary Investments	[15]	104.3		102.9
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		104.3		102.9
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	34.2		36.7
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	0		0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	34.2		36.7
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	0		0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	0		0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	22.5		17.2
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	10.2		9.7
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	12.3		7.5
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	22.5		17.2
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	10.2		9.7
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	12.3		7.5
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		996.1		981.2
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		996.1		981.2
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		996.1		981.2
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		996.1		981.2
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		52.4		58.7
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		52.4		58.7
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		52.4		58.7
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		52.4		58.7
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		8.6		8.8
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		8.6		8.8
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		8.6		8.8
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		8.6		8.8
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	[16]	1,395.3		1,461.7
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,395.3		1,461.7
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,395.3		1,461.7
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,395.3		1,461.7
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	$ 0		$ 0
[1]	Included in revenues on the statements of income.
[2]	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
[3]	Represents existing assets or liabilities that were previously categorized as Level 2.
[4]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[5]	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.
[6]	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.”
[7]	The December 31, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(4) million in 2019, $1 million in periods 2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $108 million in 2019, $37 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032. Risk management commodity contracts are substantially comprised of power contracts.
[8]	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 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.
[9]	Represents market prices in dollars per MWh.
[10]	Represents market prices in dollars per MMBtu.
[11]	Includes both affiliated and nonaffiliated transactions.
[12]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[13]	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.
[14]	Primarily represents amounts held for the repayment of debt.
[15]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[16]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[17]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended													12 Months Ended
		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															(31.7)	$ (4)		$ (30.7)
Deferred															112.8	856.6		(28.8)
Deferred Investment Tax Credits															9.2	48.6		17.6
Total Federal															90.3	901.2		(41.9)
Current															30.8	16		(10.5)
Deferred															(8.5)	44.9		(21.2)
Deferred State and Local Investment Tax Credits															2.7	7.6		(0.1)
Total State and Local															25	68.5		(31.8)
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															115.3	969.7		(73.7)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		$ 364.8		$ 579.7		$ 530.1		$ 456.7		$ 401.8		$ 556.7	$ 376.2	$ 594.2	1,931.3	1,928.9		618
Less: Equity Earnings – Dolet Hills															(73.1)	(82.4)		(71.2)
Discontinued Operations															0	0		2.5
Income Tax Expense (Benefit)															115.3	969.7		(73.7)
Pretax Income															2,043.9	2,898.6		546.8
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 429.2	$ 1,014.5		$ 191.4
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															$ 24.4	$ 60.2		$ 41.7
Investment Tax Credit Amortization															(20.2)	(18.8)		(12.3)
State and Local Income Taxes, Net															19.7	54.7		(20.7)
Removal Costs															(19.8)	(32.7)		(39.8)
AFUDC															(29.4)	(37.4)		(44.8)
Valuation Allowance															0	(1.8)		(128.3)
U.K. Windfall Tax															0	0		(12.9)
Tax Reform Adjustments															(10.9)	(26.7)		0
Tax Adjustments															0	(35.8)		(43.9)
Tax Reform Excess ADIT Reversal															(257.2)	0		0
Other															(20.5)	(6.5)		(4.1)
Income Tax Expense (Benefit)															$ 115.3	$ 969.7		$ (73.7)
Effective Income Tax Rate															5.60%	33.50%		(13.50%)
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		2,750.8								3,504.6					$ 2,750.8	$ 3,504.6
Deferred Tax Liabilities		(9,837.3)								(10,318.5)					(9,837.3)	(10,318.5)
Property Related Temporary Differences		(6,224.8)								(5,680.6)					(6,224.8)	(5,680.6)
Amounts Due from Customers for Future Federal Income Taxes		1,117.1								1,064.8					1,117.1	1,064.8
Deferred State Income Taxes	[1]	(859.9)								(1,124.4)					(859.9)	(1,124.4)
Securitized Assets		(186.6)								(257.7)					(186.6)	(257.7)
Regulatory Assets		(454.1)								(500.3)					(454.1)	(500.3)
Deferred Income Taxes on Other Comprehensive Loss		32								25.7					32	25.7
Accrued Nuclear Decommissioning		(453.7)								(457)					(453.7)	(457)
Net Operating Loss Carryforward		78.3								86.6					78.3	86.6
Tax Credit Carryforward		113.7								174.7					113.7	174.7
Investment in Partnership		(300.5)								(222)					(300.5)	(222)
All Other, Net		52								76.3					52	76.3
Net Deferred Tax Liabilities		(7,086.5)								(6,813.9)					(7,086.5)	(6,813.9)
Tax Reform Correction															233
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,								86.6						98.8	86.6	98.8		$ 187
Increase - Tax Positions Taken During a Prior Period															0.1	4.5		86
Decrease - Tax Positions Taken During a Prior Period															0	(28)		(161.2)
Increase - Tax Positions Taken During the Current Year															0	3.4		0
Decrease - Tax Positions Taken During the Current Year															0	0		0
Decrease - Settlements with Taxing Authorities															(71)	7.9		(13)
Decrease - Lapse of the Applicable Statute of Limitations															(1.1)	0		0
Balance at December 31,		14.6								86.6					14.6	86.6		98.8
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		11.6								10.5					$ 11.6	10.5		15.8
Income Taxes (Textuals) [Abstract]
Valuation Allowance																		2
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 115.3	969.7		(73.7)
Transmission and Distribution Expenses Net Income Adjustment																		21
Kentucky Single Corporate Tax Rate															5.00%
Kentucky Net Operating Loss Limitation Percent															80.00%
Remeasurement of Kentucky Deferred Taxes [Member]
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															$ (18)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Income Tax Expense (Benefit)															(18)
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Income Tax Expense (Benefit)															(18)
Income Taxes (Textuals) [Abstract]
Income Tax Expense (Benefit)															(18)
IRS Audit Settlement [Member]
Federal:
Deferred															$ (72)
AEP Texas Inc. [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															37	(85.7)		40.9
Deferred															(16.4)	63.3		29.9
Deferred Investment Tax Credits															(1.5)	(1.6)		(1.7)
Total Federal															19.1	(24)		69.1
Current															1.8	0.6		(8.8)
Deferred															(0.1)	0		(0.4)
Deferred State and Local Investment Tax Credits															0	0		0
Total State and Local															1.7	0.6		(9.2)
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															20.8	(23.4)		59.9
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		60.2		57.8		46.5		46.8		163.9		64.3	49	33.3	211.3	310.5		146.6
Discontinued Operations															0	0		48.8
Income Tax Expense (Benefit)															20.8	(23.4)		59.9
Pretax Income															232.1	287.1		255.3
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 48.7	$ 100.5		89.4
Income Tax Expense – Discontinued Operations																		$ (27.5)
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
State and Local Income Taxes, Net															$ 1.3	$ 0.4		$ (6)
AFUDC															(4.2)	(3.9)		(3.2)
Parent Company Loss Benefit															(3.1)	0		(2.5)
U.K. Windfall Tax															0	0		(12.9)
Tax Reform Adjustments															(11)	(117.4)		0
Tax Adjustments															0	(4.2)		(4.9)
Tax Reform Excess ADIT Reversal															(11.8)	0		0
Other															0.9	1.2		0
Income Tax Expense (Benefit)															$ 20.8	$ (23.4)		$ 59.9
Effective Income Tax Rate															9.00%	(8.20%)		23.50%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		208.1								221					$ 208.1	$ 221
Deferred Tax Liabilities		(1,121.2)								(1,134.1)					(1,121.2)	(1,134.1)
Property Related Temporary Differences		(836.3)								(791.5)					(836.3)	(791.5)
Amounts Due from Customers for Future Federal Income Taxes		140.6								140.9					140.6	140.9
Deferred State Income Taxes		(27.1)								(27.5)					(27.1)	(27.5)
Securitized Assets		(134.7)								(190.5)					(134.7)	(190.5)
Regulatory Assets		(53.9)								(36.4)					(53.9)	(36.4)
Deferred Income Taxes on Other Comprehensive Loss		4								4.1					4	4.1
Deferred Revenues		4.6								10.9					4.6	10.9
All Other, Net		(10.3)								(23.1)					(10.3)	(23.1)
Net Deferred Tax Liabilities		(913.1)								(913.1)					(913.1)	(913.1)
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,								(0.8)						6.5	(0.8)	6.5		$ 27.8
Increase - Tax Positions Taken During a Prior Period															0	2		6.5
Decrease - Tax Positions Taken During a Prior Period															0	(12.3)		(15)
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		(12.8)
Decrease - Lapse of the Applicable Statute of Limitations															0	0		0
Balance at December 31,		(0.8)								(0.8)					(0.8)	(0.8)		6.5
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		(0.7)								(0.5)					$ (0.7)	(0.5)		4.2
Income Taxes (Textuals) [Abstract]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 20.8	(23.4)		59.9
Transmission and Distribution Expenses Net Income Adjustment																		7
AEP Transmission Co [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															(14.2)	(130.4)	[2]	(129.4)
Deferred															82.3	254.8	[2]	205.9
Deferred Investment Tax Credits															0	0	[2]	0
Total Federal															68.1	124.4	[2]	76.5
Current															(0.6)	1.1	[2]	0.4
Deferred															16.6	16.7	[2]	17.2
Deferred State and Local Investment Tax Credits															0	0	[2]	0
Total State and Local															16	17.8	[2]	17.6
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															84.1	142.2	[2],[3]	94.1
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		71.7	[4]	78.1	[4]	82	[4]	84.1	[4]	47.7		58.6	107.4	57	315.9	270.7	[2],[3]	192.7
Income Tax Expense (Benefit)															84.1	142.2	[2],[3]	94.1
Pretax Income															400	412.9	[2]	286.8
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 84	$ 144.5	[2]	$ 100.4
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
State and Local Income Taxes, Net															$ 12.6	$ 13.1	[2]	$ 11.4
AFUDC															(14.1)	(17)	[2]	(18.3)
Tax Reform Adjustments															0	0.6	[2]	0
Other															1.6	1	[2]	0.6
Income Tax Expense (Benefit)															$ 84.1	$ 142.2	[2],[3]	$ 94.1
Effective Income Tax Rate															21.00%	34.40%	[2]	32.80%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		142.9								163	[2]				$ 142.9	$ 163	[2]
Deferred Tax Liabilities		(847.3)								(763.4)	[2]				(847.3)	(763.4)	[2]
Property Related Temporary Differences		(755)								(653.4)	[2]				(755)	(653.4)	[2]
Amounts Due from Customers for Future Federal Income Taxes		101.6								89.7	[2]				101.6	89.7	[2]
Deferred State Income Taxes	[5]	(51.9)								(77.4)	[2]				(51.9)	(77.4)	[2]
Deferred Federal Income Taxes on Deferred State Income Taxes		0								16.3	[2]				0	16.3	[2]
Net Operating Loss Carryforward		13.4								16.8	[2]				13.4	16.8	[2]
Tax Credit Carryforward		0								0.3	[2]				0	0.3	[2]
All Other, Net		(12.5)								7.3	[2]				(12.5)	7.3	[2]
Net Deferred Tax Liabilities		(704.4)								(600.4)	[2]				(704.4)	(600.4)	[2]
Tax Reform Correction															21
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]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 84.1	142.2	[2],[3]	94.1
Kentucky Single Corporate Tax Rate															5.00%
Kentucky Net Operating Loss Limitation Percent															80.00%
Appalachian Power Co [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															(31.9)	15.3		64.1
Deferred															(24.6)	166.9		125.8
Deferred Investment Tax Credits															0.1	(0.1)		(0.1)
Total Federal															(56.4)	182.1		189.8
Current															3.7	(1.4)		4.4
Deferred															7.8	4.6		4.9
Deferred State and Local Investment Tax Credits															0	0		0
Total State and Local															11.5	3.2		9.3
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															(44.9)	185.3		199.1
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		77.8		87.1		77.4		125.5		82.6		86	52.1	110.6	367.8	331.3		369.1
Income Tax Expense (Benefit)															(44.9)	185.3		199.1
Pretax Income															322.9	516.6		568.2
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 67.8	$ 180.8		$ 198.9
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															$ 8.5	$ 18		$ 19.3
State and Local Income Taxes, Net															9.1	3.5		6
Removal Costs															(9.6)	(12.4)		(12)
AFUDC															(4.3)	(5)		(6.1)
Tax Reform Adjustments															0.1	4.3		0
Tax Reform Excess ADIT Reversal															(108.5)	0		0
Other															(8)	(3.9)		(7)
Income Tax Expense (Benefit)															$ (44.9)	$ 185.3		$ 199.1
Effective Income Tax Rate															(13.90%)	35.90%		35.00%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		475.2								614.4					$ 475.2	$ 614.4
Deferred Tax Liabilities		(2,101)								(2,180.1)					(2,101)	(2,180.1)
Property Related Temporary Differences		(1,393.6)								(1,308.2)					(1,393.6)	(1,308.2)
Amounts Due from Customers for Future Federal Income Taxes		224.2								228					224.2	228
Deferred State Income Taxes	[6]	(280.3)								(335.7)					(280.3)	(335.7)
Securitized Assets		(54.3)								(59.3)					(54.3)	(59.3)
Regulatory Assets		(73.8)								(83.9)					(73.8)	(83.9)
Deferred Income Taxes on Other Comprehensive Loss		1.3								(0.4)					1.3	(0.4)
Tax Credit Carryforward		0.2								16.6					0.2	16.6
All Other, Net		(49.5)								(22.8)					(49.5)	(22.8)
Net Deferred Tax Liabilities		(1,625.8)								(1,565.7)					(1,625.8)	(1,565.7)
Tax Reform Correction															51
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,								0						0	0	0		$ 0.3
Increase - Tax Positions Taken During a Prior Period															0	0		0
Decrease - Tax Positions Taken During a Prior Period															0	0		(0.3)
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]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ (44.9)	185.3		199.1
Indiana Michigan Power Co [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															60.9	(106.5)		(44.8)
Deferred															(44.1)	202.1		104.9
Deferred Investment Tax Credits															(4.7)	(4.7)		3.8
Total Federal															12.1	90.9		63.9
Current															15.8	(8.1)		3.4
Deferred															1.2	(1.4)		0.2
Deferred State and Local Investment Tax Credits															0	0		0
Total State and Local															17	(9.5)		3.6
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															29.1	81.4		67.5
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		29.7		72.7		94.7		64.2		42.9		64.9	10.5	68.4	261.3	186.7		239.9
Income Tax Expense (Benefit)															29.1	81.4		67.5
Pretax Income															290.4	268.1		307.4
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 61	$ 93.8		$ 107.6
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															$ (0.7)	$ 11.4		$ 6.7
Investment Tax Credit Amortization															(4.7)	(4.7)		(4.7)
State and Local Income Taxes, Net															13.4	(1)		2.4
Removal Costs															(8)	(13.3)		(21.3)
AFUDC															(2.5)	(5.6)		(7.3)
Tax Reform Adjustments															0	(2.9)		0
Tax Adjustments															0	2.7		(14.2)
Tax Reform Excess ADIT Reversal															(25.8)	0		0
Other															(3.6)	1		(1.7)
Income Tax Expense (Benefit)															$ 29.1	$ 81.4		$ 67.5
Effective Income Tax Rate															10.00%	30.40%		22.00%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		771.6								1,096.4					$ 771.6	$ 1,096.4
Deferred Tax Liabilities		(1,719.6)								(2,050.2)					(1,719.6)	(2,050.2)
Property Related Temporary Differences		(445)								(403)					(445)	(403)
Amounts Due from Customers for Future Federal Income Taxes		142								137.6					142	137.6
Deferred State Income Taxes	[7]	(139.7)								(180.6)					(139.7)	(180.6)
Regulatory Assets		(31.9)								(43.8)					(31.9)	(43.8)
Deferred Income Taxes on Other Comprehensive Loss		3.7								3.9					3.7	3.9
Accrued Nuclear Decommissioning		(453.7)								(457)					(453.7)	(457)
Net Operating Loss Carryforward		0.2								1.6					0.2	1.6
All Other, Net		(23.6)								(12.5)					(23.6)	(12.5)
Net Deferred Tax Liabilities		(948)								(953.8)					(948)	(953.8)
Tax Reform Correction															48
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,								3.2						3.8	3.2	3.8		$ 2.4
Increase - Tax Positions Taken During a Prior Period															0	0.2		1.8
Decrease - Tax Positions Taken During a Prior Period															0	(0.5)		(0.4)
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	(0.3)		0
Decrease - Lapse of the Applicable Statute of Limitations															0	0		0
Balance at December 31,		3.2								3.2					3.2	3.2		3.8
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		2.6								2.1					$ 2.6	2.1		2.5
Income Taxes (Textuals) [Abstract]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 29.1	81.4		67.5
Kentucky Single Corporate Tax Rate															5.00%
Kentucky Net Operating Loss Limitation Percent															80.00%
Ohio Power Co [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															55.6	11.2		178.8
Deferred															(36.9)	141.3		(40.8)
Deferred Investment Tax Credits															0	0		0
Total Federal															18.7	152.5		138
Current															4.6	0.2		4.2
Deferred															0.7	6.6		1.6
Deferred State and Local Investment Tax Credits															0	0		0
Total State and Local															5.3	6.8		5.8
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															24	159.3		143.8
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		88.4		88.7		68.8		79.6		92.8		82.6	62.3	86.2	325.5	323.9		282.2
Income Tax Expense (Benefit)															24	159.3		143.8
Pretax Income															349.5	483.2		426
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 73.4	$ 169.1		$ 149.1
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															$ 2.6	$ 7.6		$ 7.1
State and Local Income Taxes, Net															4.2	4.4		3.8
Parent Company Loss Benefit															(5.5)	(0.2)		(7.2)
Tax Reform Adjustments															0	(14.4)		0
Tax Reform Excess ADIT Reversal															(51)	0		0
Other															0.3	(7.2)		(9)
Income Tax Expense (Benefit)															$ 24	$ 159.3		$ 143.8
Effective Income Tax Rate															6.90%	33.00%		33.80%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		209								286					$ 209	$ 286
Deferred Tax Liabilities		(972.3)								(1,048.9)					(972.3)	(1,048.9)
Property Related Temporary Differences		(826.9)								(761.2)					(826.9)	(761.2)
Amounts Due from Customers for Future Federal Income Taxes		130.9								127.3					130.9	127.3
Deferred State Income Taxes		(26.8)								(41.7)					(26.8)	(41.7)
Regulatory Assets		(55)								(107.7)					(55)	(107.7)
Deferred Income Taxes on Other Comprehensive Loss		(0.3)								(0.6)					(0.3)	(0.6)
Deferred Fuel and Purchased Power		(1.6)								(24.5)					(1.6)	(24.5)
All Other, Net		16.4								45.5					16.4	45.5
Net Deferred Tax Liabilities		(763.3)								(762.9)					(763.3)	(762.9)
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		5.4								4.5					$ 5.4	4.5		4.4
Income Taxes (Textuals) [Abstract]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 24	159.3		143.8
Kentucky Single Corporate Tax Rate															5.00%
Kentucky Net Operating Loss Limitation Percent															80.00%
Public Service Co Of Oklahoma [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															35.6	(77.1)		(28)
Deferred															(34.7)	122.7		77.2
Deferred Investment Tax Credits															(2)	(1.6)		(1.4)
Total Federal															(1.1)	44		47.8
Current															(0.2)	(0.2)		(1.9)
Deferred															3.6	2		5.3
Deferred State and Local Investment Tax Credits															2.7	4.3		3.2
Total State and Local															6.1	6.1		6.6
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															5	50.1		54.4
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		(6.6)		60.4		36.6		(7.2)		0.6		46.2	20.4	4.8	83.2	72		100
Income Tax Expense (Benefit)															5	50.1		54.4
Pretax Income															88.2	122.1		154.4
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 18.5	$ 42.7		$ 54
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															$ 1	$ 0.3		$ 0.8
Investment Tax Credit Amortization															(1.7)	(1.6)		(1.4)
State and Local Income Taxes, Net															4.8	4		4.2
Parent Company Loss Benefit															(1.4)	0		0
Tax Reform Adjustments															0	2.8		0
Tax Reform Excess ADIT Reversal															(15.5)	0		0
Other															(0.7)	1.9		(3.2)
Income Tax Expense (Benefit)															$ 5	$ 50.1		$ 54.4
Effective Income Tax Rate															5.70%	41.00%		35.20%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		229.6								269.2					$ 229.6	$ 269.2
Deferred Tax Liabilities		(837.4)								(911.2)					(837.4)	(911.2)
Property Related Temporary Differences		(609.4)								(623.8)					(609.4)	(623.8)
Amounts Due from Customers for Future Federal Income Taxes		107.1								111.6					107.1	111.6
Deferred State Income Taxes	[8]	(103.8)								(142.7)					(103.8)	(142.7)
Regulatory Assets		(32.3)								(34.4)					(32.3)	(34.4)
Deferred Income Taxes on Other Comprehensive Loss		(0.6)								(0.8)					(0.6)	(0.8)
Deferred Federal Income Taxes on Deferred State Income Taxes		0								33.5					0	33.5
Net Operating Loss Carryforward		16.4								23.1					16.4	23.1
Tax Credit Carryforward		0								0.7					0	0.7
All Other, Net		14.8								(9.2)					14.8	(9.2)
Net Deferred Tax Liabilities		(607.8)								(642)					(607.8)	(642)
Tax Reform Correction															33
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,								0						0.1	0	0.1		$ 1.3
Increase - Tax Positions Taken During a Prior Period															0	0.1		0.1
Decrease - Tax Positions Taken During a Prior Period															0	(0.9)		(1.3)
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	0.7		0
Decrease - Lapse of the Applicable Statute of Limitations															0	0		0
Balance at December 31,		0								0					0	0		0.1
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		0								0					$ 0	0		0.1
Income Taxes (Textuals) [Abstract]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 5	50.1		54.4
Transmission and Distribution Expenses Net Income Adjustment																		2
Southwestern Electric Power Co [Member]
Federal Tax Reform [Abstract]
Section 168(k) - General Regulated Utilities Bonus Depreciation Expense Percentage															0.00%
Section 168(k) - General Max Competitive Utilities Bonus Depreciation Expense Percentage															100.00%
Section 168(k) - Previous General Competitive Utilities Bonus Depreciation Expense Percentage															50.00%
Tax Reform - Less Than Allocable Competitive Business Interest Expense Percentage Requirement															10.00%
Section 162(m) - General Compensation Deduction Limit															$ 1
Federal:
Current															18.3	(30.1)		(96.7)
Deferred															(0.5)	84.8		172.6
Deferred Investment Tax Credits															(1.4)	(1.4)		(1.2)
Total Federal															16.4	53.3		74.7
Current															2.3	(0.9)		(12.6)
Deferred															1.7	(4.3)		(10)
Deferred State and Local Investment Tax Credits															0	0		0
Total State and Local															4	(5.2)		(22.6)
Income Tax Expense (Benefit):
Income Tax Expense (Benefit)															20.4	48.1		52.1
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income		10.5		$ 89.6		$ 38.7		13.4		11		$ 84.1	$ 25.1	17.3	152.2	137.5		169.7
Less: Equity Earnings – Dolet Hills															(2.7)	3.8		(7.9)
Income Tax Expense (Benefit)															20.4	48.1		52.1
Pretax Income															169.9	185.6		221.8
Income Taxes on Pretax Income at Statutory Rate (21%, 35% and 35% in 2018, 2017 and 2016, Respectively)															$ 35.7	$ 65		$ 77.6
Federal Statutory Income Tax Rate															21.00%	35.00%		35.00%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation															$ 3.4	$ 1.9		$ 3.2
Depletion															(3.2)	(5.7)		(5.5)
State and Local Income Taxes, Net															3.2	(2.3)		(14.7)
AFUDC															(1.3)	(0.9)		(3.9)
Tax Reform Adjustments															0	(0.4)		0
Tax Adjustments															0	(9.9)		(0.9)
Tax Reform Excess ADIT Reversal															(16)	0		0
Other															(1.4)	0.4		(3.7)
Income Tax Expense (Benefit)															$ 20.4	$ 48.1		$ 52.1
Effective Income Tax Rate															12.00%	25.90%		23.50%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets		317.4								349.4					$ 317.4	$ 349.4
Deferred Tax Liabilities		(1,220.2)								(1,267.1)					(1,220.2)	(1,267.1)
Property Related Temporary Differences		(929.1)								(908.8)					(929.1)	(908.8)
Amounts Due from Customers for Future Federal Income Taxes		145.8								135.8					145.8	135.8
Deferred State Income Taxes	[9]	(156)								(189.2)					(156)	(189.2)
Regulatory Assets		(30.8)								(30.8)					(30.8)	(30.8)
Deferred Income Taxes on Other Comprehensive Loss		1.4								1.3					1.4	1.3
Capital/Impairment Loss – Turk Plant		15.8								17.4					15.8	17.4
Net Operating Loss Carryforward		36.2								38.7					36.2	38.7
Tax Credit Carryforward		0								0.8					0	0.8
All Other, Net		13.9								17.1					13.9	17.1
Net Deferred Tax Liabilities		(902.8)								(917.7)					(902.8)	(917.7)
Tax Reform Correction															38
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,								$ (0.8)						$ 1.3	(0.8)	1.3		$ 9.3
Increase - Tax Positions Taken During a Prior Period															0	1.7		1.3
Decrease - Tax Positions Taken During a Prior Period															0	(5.4)		(9.3)
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	1.6		0
Decrease - Lapse of the Applicable Statute of Limitations															0	0		0
Balance at December 31,		(0.8)								(0.8)					(0.8)	(0.8)		1.3
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount		(0.6)								$ (0.5)					$ (0.6)	(0.5)		0.8
Income Taxes (Textuals) [Abstract]
Period with No Change in Unrecognized Tax Benefits															12 months
Income Tax Expense (Benefit)															$ 20.4	48.1		52.1
Transmission and Distribution Expenses Net Income Adjustment																		9
Arkansas [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		67.8													$ 67.8
Arkansas [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2018
Arkansas [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2023
Arkansas [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		67.1													$ 67.1
Arkansas [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2021
Arkansas [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2023
Kentucky [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		130.4													$ 130.4
Kentucky [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2025
Kentucky [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Louisiana [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		517.3													$ 517.3
Louisiana [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2030
Louisiana [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2038
Louisiana [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		504.9													$ 504.9
Louisiana [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2032
Louisiana [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		644.2													$ 644.2
Oklahoma [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2032
Oklahoma [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
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		264													$ 264
Oklahoma [Member] | AEP Transmission Co [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2032
Oklahoma [Member] | AEP Transmission Co [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
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		348.8													$ 348.8
Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2034
Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Tennessee [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		28.6													$ 28.6
Tennessee [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2025
Tennessee [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2033
Virginia [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		22.8													$ 22.8
Virginia [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2030
Virginia [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2038
West Virginia [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		5.1													$ 5.1
West Virginia [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2029
West Virginia [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
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		3.8													$ 3.8
West Virginia [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2032
West Virginia [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2037
Ohio Municipal [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		226.5													$ 226.5
Ohio Municipal [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2019
Ohio Municipal [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2023
Ohio Municipal [Member] | AEP Transmission Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward		43.6													$ 43.6
Ohio Municipal [Member] | AEP Transmission Co [Member] | Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2019
Ohio Municipal [Member] | AEP Transmission Co [Member] | Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date															Dec. 31, 2023
Federal [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		113.7													$ 113.7
Tax Credit Carryforward Amount To Expire If Not Used		100.9													$ 100.9
Federal [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2037
Federal [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2038
Federal [Member] | Appalachian Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0.2													$ 0.2
Tax Credit Carryforward Amount To Expire If Not Used		0													$ 0
Federal [Member] | Appalachian Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2037
Federal [Member] | Appalachian Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2038
Federal [Member] | Indiana Michigan Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0.9													$ 0.9
Tax Credit Carryforward Amount To Expire If Not Used		0													$ 0
Federal [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2037
Federal [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2038
Federal [Member] | Public Service Co Of Oklahoma [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													$ 0
Tax Credit Carryforward Amount To Expire If Not Used		0													$ 0
Federal [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Jan. 1, 2037
Federal [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date															Dec. 31, 2038
Net Tax Benefit [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Income Tax Expense – Discontinued Operations															$ 0	0		0
Net Tax Benefit [Member] | AEP Texas Inc. [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Income Tax Expense – Discontinued Operations															0	0		27.6
Expiration of Charitable Contribution Carryforward Deductions [Member]
Income Taxes (Textuals) [Abstract]
Valuation Allowance																		6
2011 Audit Issue Settlement [Member]
Income Taxes (Textuals) [Abstract]
Valuation Allowance																		56
Certain Assets Held for Sale and 2015 Federal Income Tax Return [Member]
Income Taxes (Textuals) [Abstract]
Valuation Allowance																		66
State and Local Jurisdiction [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		34.2													34.2
Tax Credit Carryforward Amount To Expire If Not Used		0													0
Income Taxes (Textuals) [Abstract]
Valuation Allowance		5													5
State and Local Jurisdiction [Member] | AEP Transmission Co [Member]
Income Taxes (Textuals) [Abstract]
Valuation Allowance		1													1
State and Local Jurisdiction [Member] | Appalachian Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		0													0
Tax Credit Carryforward Amount To Expire If Not Used		0													0
State and Local Jurisdiction [Member] | Public Service Co Of Oklahoma [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount		34.2													34.2
Tax Credit Carryforward Amount To Expire If Not Used		$ 0													0
Dolet Hills Lignite Co, LLC [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Less: Equity Earnings – Dolet Hills															(2.7)	0		0
Dolet Hills Lignite Co, LLC [Member] | Southwestern Electric Power Co [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Less: Equity Earnings – Dolet Hills															$ (2.7)	$ 0		$ 0
[1]	In 2018, AEP recorded a $233 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[3]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[4]	The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1.
[5]	In 2018, AEPTCo recorded a $21 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.
[6]	In 2018, APCo recorded a $51 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.
[7]	In 2018, I&M recorded a $48 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.
[8]	In 2018, PSO recorded a $33 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.
[9]	In 2018, SWEPCo recorded a $38 million correction related to the accounting for the impact of Tax Reform in 2017. The correction resulted in a decrease in Net Deferred Tax Liabilities with an offsetting increase to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018. Management concluded the misstatement was not material to the 2017 financial statements or the financial statements of any of the interim periods in 2018.

Leases (Details)

Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Lease Rental Costs
Net Lease Expense on Operating Leases		$ 245	$ 231.3	$ 224.9
Amortization of Capital Leases		62.4	66.3	93.7
Interest on Capital Leases		16.4	16.7	18.9
Total Lease Rental Costs		323.8	314.3	337.5
PP&E and Related Obligations Under Capital Leases
Generation		131.3	141.7
Other Property, Plant and Equipment		373.9	373.3
Total Property, Plant and Equipment Under Capital Leases		505.2	515
Accumulated Amortization		226.4	229
Net Property, Plant and Equipment Under Capital Leases		278.8	286
Noncurrent Liability		233.5	238.8
Liability Due Within One Year		55.5	59
Total Obligations Under Capital Leases		289	297.8
Future Minimum Lease Payments
Capital Leases, 2019		70.8
Capital Leases, 2020		60.2
Capital Leases, 2021		51.7
Capital Leases, 2022		43.8
Capital Leases, 2023		35.5
Capital Leases, Later Years		90.2
Capital Leases, Total Future Minimum Lease Payments		352.2
Less Estimated Interest Element on Capital Leases		63.2
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		289
Noncancelable Operating Leases, 2019		259.6
Noncancelable Operating Leases, 2020		250.1
Noncancelable Operating Leases, 2021		232.7
Noncancelable Operating Leases, 2022		222.5
Noncancelable Operating Leases, 2023		58.3
Noncancelable Operating Leases, Later Years		165.2
Noncancelable Operating Leases, Total Future Minimum Lease Payments		1,188.4
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		$ 47.7
Leases (Textuals)
Maximum Remaining Lease Term		17 years
Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,019	[1]	$ 147.8
2,020	[1]	147.8
2,021	[1]	147.8
2,022	[1]	147.2
Total Future Minimum Lease Payments	[1]	$ 590.6
Leases (Textuals)
Lease Term		33 years
Boat and Barge Leases [Member]
Leases (Textuals)
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases		$ 44
Guarantor Obligations, Current Carrying Value		5
Guarantee Obligations Current Carrying Value Other Liabilities Current		1
Guarantee Obligations Current Carrying Value Other Liabilities Noncurrent		4
AEP Texas Inc. [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		13.6	10.5	9.8	[2]
Amortization of Capital Leases		4.8	4	3.4
Interest on Capital Leases		1.2	0.8	0.6
Total Lease Rental Costs		19.6	15.3	13.8
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		38.8	32.7
Total Property, Plant and Equipment Under Capital Leases		38.8	32.7
Accumulated Amortization		10.3	10
Net Property, Plant and Equipment Under Capital Leases		28.5	22.7
Noncurrent Liability		24	18.5
Liability Due Within One Year		4.5	4.2
Total Obligations Under Capital Leases		28.5	22.7
Future Minimum Lease Payments
Capital Leases, 2019		5.8
Capital Leases, 2020		5.3
Capital Leases, 2021		4.7
Capital Leases, 2022		4.2
Capital Leases, 2023		3.7
Capital Leases, Later Years		10.1
Capital Leases, Total Future Minimum Lease Payments		33.8
Less Estimated Interest Element on Capital Leases		5.3
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		28.5
Noncancelable Operating Leases, 2019		15.1
Noncancelable Operating Leases, 2020		14.1
Noncancelable Operating Leases, 2021		13.2
Noncancelable Operating Leases, 2022		12.2
Noncancelable Operating Leases, 2023		10.8
Noncancelable Operating Leases, Later Years		28.4
Noncancelable Operating Leases, Total Future Minimum Lease Payments		93.8
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		10.8
Leases (Textuals)
Lease Expenses Related to Discontinued Operations				1
AEP Transmission Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		2.7	1.7	0.9
Amortization of Capital Leases		0.1	0	0
Interest on Capital Leases		0	0	0
Total Lease Rental Costs		2.8	1.7	0.9
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		0.2	0.2
Total Property, Plant and Equipment Under Capital Leases		0.2	0.2
Accumulated Amortization		0.1	0
Net Property, Plant and Equipment Under Capital Leases		0.1	0.2
Noncurrent Liability		0	0.1
Liability Due Within One Year		0.1	0.1
Total Obligations Under Capital Leases		0.1	0.2
Future Minimum Lease Payments
Capital Leases, 2019		0.1
Capital Leases, 2020		0
Capital Leases, 2021		0
Capital Leases, 2022		0
Capital Leases, 2023		0
Capital Leases, Later Years		0
Capital Leases, Total Future Minimum Lease Payments		0.1
Less Estimated Interest Element on Capital Leases		0
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		0.1
Noncancelable Operating Leases, 2019		2.3
Noncancelable Operating Leases, 2020		1.8
Noncancelable Operating Leases, 2021		1
Noncancelable Operating Leases, 2022		0.5
Noncancelable Operating Leases, 2023		0.1
Noncancelable Operating Leases, Later Years		0
Noncancelable Operating Leases, Total Future Minimum Lease Payments		5.7
Appalachian Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		18.2	17.5	16.6
Amortization of Capital Leases		7	6.9	6.4
Interest on Capital Leases		3	3.7	3.5
Total Lease Rental Costs		28.2	28.1	26.5
PP&E and Related Obligations Under Capital Leases
Generation		38.7	42.5
Other Property, Plant and Equipment		17.3	18
Total Property, Plant and Equipment Under Capital Leases		56	60.5
Accumulated Amortization		16.2	19
Net Property, Plant and Equipment Under Capital Leases		39.8	41.5
Noncurrent Liability		33.7	34.9
Liability Due Within One Year		6.1	6.6
Total Obligations Under Capital Leases		39.8	41.5
Future Minimum Lease Payments
Capital Leases, 2019		9
Capital Leases, 2020		8
Capital Leases, 2021		7.3
Capital Leases, 2022		6.8
Capital Leases, 2023		6.3
Capital Leases, Later Years		13.3
Capital Leases, Total Future Minimum Lease Payments		50.7
Less Estimated Interest Element on Capital Leases		10.9
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		39.8
Noncancelable Operating Leases, 2019		17.6
Noncancelable Operating Leases, 2020		16.5
Noncancelable Operating Leases, 2021		13.9
Noncancelable Operating Leases, 2022		12.8
Noncancelable Operating Leases, 2023		9.9
Noncancelable Operating Leases, Later Years		20.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		91.2
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		89.2	88.4	90.5
Amortization of Capital Leases		6.6	11.1	35.6
Interest on Capital Leases		3.3	3.2	3.7
Total Lease Rental Costs		99.1	102.7	129.8
PP&E and Related Obligations Under Capital Leases
Generation		27	27.2
Other Property, Plant and Equipment		33.3	34
Total Property, Plant and Equipment Under Capital Leases		60.3	61.2
Accumulated Amortization		21.6	21.1
Net Property, Plant and Equipment Under Capital Leases		38.7	40.1
Noncurrent Liability		33.4	34.3
Liability Due Within One Year		5.3	5.8
Total Obligations Under Capital Leases		38.7	40.1
Future Minimum Lease Payments
Capital Leases, 2019		8.2
Capital Leases, 2020		7.2
Capital Leases, 2021		6.6
Capital Leases, 2022		6.1
Capital Leases, 2023		5.7
Capital Leases, Later Years		21.7
Capital Leases, Total Future Minimum Lease Payments		55.5
Less Estimated Interest Element on Capital Leases		16.8
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		38.7
Noncancelable Operating Leases, 2019		92.6
Noncancelable Operating Leases, 2020		89.3
Noncancelable Operating Leases, 2021		84.8
Noncancelable Operating Leases, 2022		83.8
Noncancelable Operating Leases, 2023		6.5
Noncancelable Operating Leases, Later Years		19.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		376.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.7
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,019		73.9
2,020		73.9
2,021		73.9
2,022		73.6
Total Future Minimum Lease Payments		$ 295.3
Leases (Textuals)
Lease Term		33 years
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Leases (Textuals)
Future Minimum Lease Obligation for Remaining Railcars		$ 6
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 5
Ohio Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		10.7	8.2	7.1
Amortization of Capital Leases		3.9	4.1	4.2
Interest on Capital Leases		0.5	0.5	0.5
Total Lease Rental Costs		15.1	12.8	11.8
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		20.4	22.8
Total Property, Plant and Equipment Under Capital Leases		20.4	22.8
Accumulated Amortization		8.3	10.6
Net Property, Plant and Equipment Under Capital Leases		12.1	12.2
Noncurrent Liability		9.2	7.9
Liability Due Within One Year		2.9	4.3
Total Obligations Under Capital Leases		12.1	12.2
Future Minimum Lease Payments
Capital Leases, 2019		3.3
Capital Leases, 2020		2.7
Capital Leases, 2021		2.3
Capital Leases, 2022		1.7
Capital Leases, 2023		1.2
Capital Leases, Later Years		2.8
Capital Leases, Total Future Minimum Lease Payments		14
Less Estimated Interest Element on Capital Leases		1.9
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		12.1
Noncancelable Operating Leases, 2019		14.5
Noncancelable Operating Leases, 2020		13.2
Noncancelable Operating Leases, 2021		10.9
Noncancelable Operating Leases, 2022		10
Noncancelable Operating Leases, 2023		8.8
Noncancelable Operating Leases, Later Years		31.7
Noncancelable Operating Leases, Total Future Minimum Lease Payments		89.1
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		7.9
Public Service Co Of Oklahoma [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		5.7	4.4	5
Amortization of Capital Leases		3.2	4	3.7
Interest on Capital Leases		0.4	0.6	0.6
Total Lease Rental Costs		9.3	9	9.3
PP&E and Related Obligations Under Capital Leases
Generation		2.6	8.9
Other Property, Plant and Equipment		17.6	18
Total Property, Plant and Equipment Under Capital Leases		20.2	26.9
Accumulated Amortization		7.9	15.3
Net Property, Plant and Equipment Under Capital Leases		12.3	11.6
Noncurrent Liability		9.5	8.3
Liability Due Within One Year		2.8	3.5
Total Obligations Under Capital Leases		12.3	11.8
Future Minimum Lease Payments
Capital Leases, 2019		3.4
Capital Leases, 2020		2.6
Capital Leases, 2021		2
Capital Leases, 2022		1.6
Capital Leases, 2023		1.4
Capital Leases, Later Years		3.3
Capital Leases, Total Future Minimum Lease Payments		14.3
Less Estimated Interest Element on Capital Leases		2
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		12.3
Noncancelable Operating Leases, 2019		6.5
Noncancelable Operating Leases, 2020		6
Noncancelable Operating Leases, 2021		5
Noncancelable Operating Leases, 2022		4.6
Noncancelable Operating Leases, 2023		4.1
Noncancelable Operating Leases, Later Years		10.7
Noncancelable Operating Leases, Total Future Minimum Lease Payments		36.9
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.8
Southwestern Electric Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		6.5	5.3	6.7
Amortization of Capital Leases		11.2	11.2	13.6
Interest on Capital Leases		3.2	3.6	5.1
Total Lease Rental Costs		20.9	20.1	$ 25.4
PP&E and Related Obligations Under Capital Leases
Generation		34.3	33.4
Other Property, Plant and Equipment		119.8	122.4
Total Property, Plant and Equipment Under Capital Leases		154.1	155.8
Accumulated Amortization		99.9	94
Net Property, Plant and Equipment Under Capital Leases		54.2	61.8
Noncurrent Liability		50.6	57.8
Liability Due Within One Year		10.2	11.2
Total Obligations Under Capital Leases		60.8	$ 69
Future Minimum Lease Payments
Capital Leases, 2019		13.1
Capital Leases, 2020		11.5
Capital Leases, 2021		10.5
Capital Leases, 2022		9.4
Capital Leases, 2023		8.6
Capital Leases, Later Years		18.7
Capital Leases, Total Future Minimum Lease Payments		71.8
Less Estimated Interest Element on Capital Leases		11
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		60.8
Noncancelable Operating Leases, 2019		7.4
Noncancelable Operating Leases, 2020		7.2
Noncancelable Operating Leases, 2021		6.7
Noncancelable Operating Leases, 2022		6.1
Noncancelable Operating Leases, 2023		5
Noncancelable Operating Leases, Later Years		11.7
Noncancelable Operating Leases, Total Future Minimum Lease Payments		44.1
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		4.3
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Leases (Textuals)
Future Minimum Lease Obligation for Remaining Railcars		$ 7
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 5
[1]	AEP’s future minimum lease payments include equal shares from AEGCo and I&M.
[2]	Amounts include lease expenses related to Desert Sky and Trent that were classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for the year ended December 31, 2016. See Note 7 - Dispositions and Impairments for additional information.

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		Feb. 21, 2019	Jan. 31, 2019	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Shares of Company
Beginning Balance, Shares			513,450,036	512,210,644	512,048,520		511,389,173
Issued				1,239,392	162,124		659,347
Ending Balance, Shares				513,450,036	512,210,644		512,048,520
Treasury Stock, Shares, Beginning Balance			20,204,160	20,205,046	20,336,592		20,336,592
Partners' Capital Account, Units, Treasury Units Reissued	[1]			(886)	(131,546)
Treasury Stock, Shares, Ending Balance				20,204,160	20,205,046		20,336,592
Long-term Debt
Senior Unsecured Notes				$ 18,903.3	$ 16,478.3
Pollution Control Bonds	[2]			1,643.8	1,621.7
Notes Payable	[3]			204.7	260.8
Securitization Bonds				1,111.4	1,416.5
Spent Nuclear Fuel Obligation	[4]			273.6	268.6
Other Long-term Debt				1,209.9	1,127.4
Total Long-term Debt Outstanding				23,346.7	21,173.3
Outstanding Long-term Debt
Principal Amount, 2019				1,698.5
Principal Amount, 2020				1,508.3
Principal Amount, 2021				1,961.5
Principal Amount, 2022				1,668.4
Principal Amount, 2023				539.6
Principal Amount, After 2023				16,150.9
Principal Amount, Total				23,527.2
Unamortized Discount, Net and Debt Issuance Costs				(180.5)
Total Long-term Debt Outstanding				23,346.7	21,173.3
Short-term Debt
Securitized Debt for Receivables	[5]			750	718
Commercial Paper				1,160	898.6
Notes Payable				0	22
Total Short-term Debt				$ 1,910	$ 1,638.6
Securitized Debt for Receivables	[5],[6]			2.16%	1.22%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable				2.16%	1.22%		0.70%
Net Uncollectible Accounts Receivable Written Off				$ 27.6	$ 23.4		$ 23.7
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts				972.5	925.5
Total Principal Outstanding				750	718
Delinquent Securitized Accounts Receivable				50.3	41.1
Bad Debt Reserves Related to Securitized Sale of Accounts Receivable				27.5	28.7
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable				281.4	303.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				16,195.7	15,424.9		16,380.1
Financing Activities (Textuals)
Repayments of Long-term Debt				2,782	3,087.9		1,794.9
Proceeds from Issuance of Long-term Debt				4,945.7	3,854.1		2,594.9
Total Commitment From Bank Conduits To Finance Receivables				750
Reaquired Pollution Control Bonds Held by Trustees				$ 574
Maximum Percentage Debt to Capitalization				67.50%
Restricted Net Assets				$ 12,400
Retained Earnings Available to Pay Dividends				7,700
Dividend Restrictions	[7]			1,591.4
Dividends Paid on Common Stock				(1,255.5)	$ (1,191.9)		(1,121)
Credit Facilities, Total				4,000
Maximum Amount of Commercial Paper Outstanding				$ 2,300
Weighted Average Interest Rate of Commercial Paper Outstanding During Year				2.332%
Commercial Paper [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[6]			2.9649%	1.85%
Loans Payable [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[6]			0.00%	2.92%
AEP Texas Inc. [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,398.4	$ 1,932.2
Pollution Control Bonds				490.9	490.5
Securitization Bonds				791.2	1,026.1
Other Long-term Debt				200.8	200.5
Total Long-term Debt Outstanding				3,881.3	3,649.3
Outstanding Long-term Debt
Principal Amount, 2019				501.1
Principal Amount, 2020				377.7
Principal Amount, 2021				66.2
Principal Amount, 2022				493
Principal Amount, 2023				195
Principal Amount, After 2023				2,275.5
Principal Amount, Total				3,908.5
Unamortized Discount, Net and Debt Issuance Costs				(27.2)
Total Long-term Debt Outstanding				3,881.3	3,649.3
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				1,493
Financing Activities (Textuals)
Repayments of Long-term Debt				266.1	323.1		428.7
Proceeds from Issuance of Long-term Debt				$ 494	749.6		199.2
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 353.7
Dividends Paid on Common Stock				0	0		$ (34)
AEP Texas Inc. [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				390.6	296
Maximum Loans to Money Pool				106.9	451.7
Average Borrowings from Money Pool				176	194.8
Average Loans to Money Pool				47.1	264.6
Net Loans (Borrowings) to/from Money Pool				(216)	103.5
Authorized Short Term Borrowing Limit				$ 500	$ 400
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.26%	1.29%		0.88%
Average Interest Rate For Funds Loaned				2.29%	1.26%		0.72%
AEP Texas Inc. [Member] | Nonutility [Member]
Maximum Interest Rate for Funds Borrowed				0.00%	0.00%		1.11%
Minimum Interest Rate For Funds Borrowed				0.00%	0.00%		0.97%
Maximum Interest Rate For Funds Loaned				2.97%	1.85%		1.02%
Minimum Interest Rate for Funds Loaned				1.83%	0.00%		0.75%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Loans to Money Pool				$ 8.4	$ 8.6
Average Loans to Money Pool				8.1	8.3
Net Loans (Borrowings) to/from Money Pool				$ 8	$ 8.4
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.00%	0.00%		1.00%
Average Interest Rate For Funds Loaned				2.36%	1.32%		0.86%
AEP Texas Inc. [Member] | Direct Borrowing [Member]
Maximum Interest Rate for Funds Borrowed				0.00%	0.00%		0.98%
Minimum Interest Rate For Funds Borrowed				0.00%	0.00%		0.69%
Maximum Interest Rate For Funds Loaned				0.00%	0.00%		1.02%
Minimum Interest Rate for Funds Loaned				0.00%	0.00%		0.99%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.00%	0.00%		0.83%
Average Interest Rate For Funds Loaned				0.00%	0.00%		1.00%
AEP Transmission Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,823	$ 2,550.4
Total Long-term Debt Outstanding				2,823	2,550.4	[8]
Outstanding Long-term Debt
Principal Amount, 2019				85
Principal Amount, 2020				0
Principal Amount, 2021				50
Principal Amount, 2022				104
Principal Amount, 2023				60
Principal Amount, After 2023				2,551
Principal Amount, Total				2,850
Unamortized Discount, Net and Debt Issuance Costs				(27)
Total Long-term Debt Outstanding				2,823	2,550.4	[8]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				832
Financing Activities (Textuals)
Repayments of Long-term Debt				50	0		$ 300
Proceeds from Issuance of Long-term Debt				321	617.6		$ 686.9
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				371.3	467.2
Maximum Loans to Money Pool				276.4	268
Average Borrowings from Money Pool				177.9	180.5
Average Loans to Money Pool				58.4	119.8
Net Loans (Borrowings) to/from Money Pool				35.8	109.2
Authorized Short Term Borrowing Limit	[9]			$ 795	$ 795
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.27%	1.36%		0.85%
Average Interest Rate For Funds Loaned				2.10%	1.27%		0.83%
AEP Transmission Co [Member] | Direct Borrowing [Member]
Maximum Interest Rate for Funds Borrowed				2.97%	1.85%		1.02%
Minimum Interest Rate For Funds Borrowed				1.76%	0.92%		0.69%
Maximum Interest Rate For Funds Loaned				2.97%	1.85%		1.02%
Minimum Interest Rate for Funds Loaned				1.76%	0.92%		0.69%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 1.2	$ 4.1
Maximum Loans to Money Pool				104.7	151.9
Average Borrowings from Money Pool				1.1	1.1
Average Loans to Money Pool				49.8	39.3
Borrowings from Parent				1.2	1.1
Loans to Parent				16.9	22.5
Authorized Short Term Borrowing Limit	[10]			$ 75	$ 75
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.36%	1.33%		0.83%
Average Interest Rate For Funds Loaned				2.36%	1.36%		0.87%
Appalachian Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 3,047.3	$ 3,045.1
Pollution Control Bonds	[2]			616	512.2
Securitization Bonds				272.3	295.9
Other Long-term Debt				127	126.9
Total Long-term Debt Outstanding				4,062.6	3,980.1
Outstanding Long-term Debt
Principal Amount, 2019				430.7
Principal Amount, 2020				90.3
Principal Amount, 2021				393
Principal Amount, 2022				230.4
Principal Amount, 2023				26.6
Principal Amount, After 2023				2,924.4
Principal Amount, Total				4,095.4
Unamortized Discount, Net and Debt Issuance Costs				(32.8)
Total Long-term Debt Outstanding				4,062.6	3,980.1
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				133.3	136.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				2,993.2
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,421	1,372.8		$ 1,412.5
Financing Activities (Textuals)
Repayments of Long-term Debt				124	377.9		213.6
Proceeds from Issuance of Long-term Debt				$ 203.2	320.9		$ 314
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 17.6
Appalachian Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				295.5	231.5
Maximum Loans to Money Pool				23.7	160.7
Average Borrowings from Money Pool				175.3	144.3
Average Loans to Money Pool				23.3	30
Net Loans (Borrowings) to/from Money Pool				(182.6)	(162.5)
Authorized Short Term Borrowing Limit				$ 600	$ 600
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.26%	1.28%		0.80%
Average Interest Rate For Funds Loaned				2.21%	1.29%		0.82%
Indiana Michigan Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,149	$ 1,809
Pollution Control Bonds	[2]			264.5	264.6
Notes Payable	[3]			135.8	188.6
Spent Nuclear Fuel Obligation	[4]			273.6	268.6
Other Long-term Debt				212.5	214.3
Total Long-term Debt Outstanding				3,035.4	2,745.1
Outstanding Long-term Debt
Principal Amount, 2019				155.4
Principal Amount, 2020				41.6
Principal Amount, 2021				256.4
Principal Amount, 2022				7
Principal Amount, 2023				252.4
Principal Amount, After 2023				2,351.5
Principal Amount, Total				3,064.3
Unamortized Discount, Net and Debt Issuance Costs				(28.9)
Total Long-term Debt Outstanding				3,035.4	2,745.1
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				152.9	136.5
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				2,381
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,843	1,612.9		$ 1,596.2
Financing Activities (Textuals)
Repayments of Long-term Debt				884.9	260.7		100.2
Proceeds from Issuance of Long-term Debt				$ 1,168.1	530.1		$ 569.4
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 454.1
Indiana Michigan Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				322.1	367.4
Maximum Loans to Money Pool				657.8	12.6
Average Borrowings from Money Pool				255.5	204.9
Average Loans to Money Pool				110.7	12.6
Net Loans (Borrowings) to/from Money Pool				11.6	(199.2)
Authorized Short Term Borrowing Limit				$ 500	$ 500
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.16%	1.27%		0.80%
Average Interest Rate For Funds Loaned				2.08%	1.29%		0.80%
Ohio Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,635.5	$ 1,591.4
Pollution Control Bonds				32.3	32.3
Securitization Bonds				47.8	94.5
Other Long-term Debt				1	1.1
Total Long-term Debt Outstanding				1,716.6	1,719.3
Outstanding Long-term Debt
Principal Amount, 2019				47.9
Principal Amount, 2020				0.1
Principal Amount, 2021				500.1
Principal Amount, 2022				0.1
Principal Amount, 2023				0.1
Principal Amount, After 2023				1,182.8
Principal Amount, Total				1,731.1
Unamortized Discount, Net and Debt Issuance Costs				(14.5)
Total Long-term Debt Outstanding				1,716.6	1,719.3
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				395.2	367.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				3,079.9
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				2,674.5	2,339		$ 2,633
Financing Activities (Textuals)
Repayments of Long-term Debt				397.1	46.4		395.9
Proceeds from Issuance of Long-term Debt				392.8	0		$ 0
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				270.8	280.6
Maximum Loans to Money Pool				225	56.2
Average Borrowings from Money Pool				167.8	137
Average Loans to Money Pool				189.4	27.9
Net Loans (Borrowings) to/from Money Pool				(114.1)	(87.8)
Authorized Short Term Borrowing Limit				$ 500	$ 400
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.18%	1.37%		0.85%
Average Interest Rate For Funds Loaned				2.47%	0.98%		0.74%
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				$ 1,144.9	$ 1,144.1
Pollution Control Bonds				12.6	12.6
Other Long-term Debt				129.5	129.8
Total Long-term Debt Outstanding				1,287	1,286.5
Outstanding Long-term Debt
Principal Amount, 2019				375.5
Principal Amount, 2020				13.2
Principal Amount, 2021				250.5
Principal Amount, 2022				0.5
Principal Amount, 2023				0.5
Principal Amount, After 2023				652
Principal Amount, Total				1,292.2
Unamortized Discount, Net and Debt Issuance Costs				(5.2)
Total Long-term Debt Outstanding				1,287	1,286.5
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				109.7	115.1
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				1,536.4
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,484.6	1,337		$ 1,269.3
Financing Activities (Textuals)
Repayments of Long-term Debt				0.5	0.5		275.4
Proceeds from Issuance of Long-term Debt				$ 0	0		$ 274.2
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 152.7
Public Service Co Of Oklahoma [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				193.7	185.2
Maximum Loans to Money Pool				31.8	0
Average Borrowings from Money Pool				104.5	119.3
Average Loans to Money Pool				12.9	0
Net Loans (Borrowings) to/from Money Pool				(105.5)	(149.6)
Authorized Short Term Borrowing Limit				$ 300	$ 300
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.27%	1.32%		0.96%
Average Interest Rate For Funds Loaned				1.98%	0.00%		0.83%
Southwestern Electric Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,427	$ 2,110.7
Pollution Control Bonds				53.5	135.1
Notes Payable	[3]			68.9	72.1
Other Long-term Debt				164	124
Total Long-term Debt Outstanding				2,713.4	2,441.9
Outstanding Long-term Debt
Principal Amount, 2019				59.7
Principal Amount, 2020				121.2
Principal Amount, 2021				6.2
Principal Amount, 2022				281.2
Principal Amount, 2023				6.2
Principal Amount, After 2023				2,262.9
Principal Amount, Total				2,737.4
Unamortized Discount, Net and Debt Issuance Costs				(24)
Total Long-term Debt Outstanding				2,713.4	2,441.9
Short-term Debt
Notes Payable				0	22
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				150.3	138.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				1,817
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,736.1	1,563.4		$ 1,531.7
Financing Activities (Textuals)
Repayments of Long-term Debt				794.5	353.7		3.3
Proceeds from Issuance of Long-term Debt				$ 1,065.7	114.6		406.7
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 526.4
Dividends Paid on Common Stock				(4.3)	(13.6)		$ (4.2)
Southwestern Electric Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				200.1	187.5
Maximum Loans to Money Pool				533.7	178.6
Average Borrowings from Money Pool				143.2	95.5
Average Loans to Money Pool				268.1	169.5
Net Loans (Borrowings) to/from Money Pool				81.4	(118.7)
Authorized Short Term Borrowing Limit				$ 350	$ 350
Maximum and Minimum Interest Rates
Maximum Interest Rate				2.97%	1.85%		1.02%
Minimum Interest Rate				1.81%	0.92%		0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.31%	1.28%		0.79%
Average Interest Rate For Funds Loaned				2.00%	0.98%		0.90%
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				2.97%	1.85%		1.02%
Minimum Interest Rate for Funds Loaned				1.83%	0.00%		0.69%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Loans to Money Pool				$ 2	$ 2
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				2.36%	1.32%		0.82%
Southwestern Electric Power Co [Member] | Loans Payable [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[6]			0.00%	2.92%
Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,048
Weighted Average Interest Rate				4.36%
Senior Notes [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.15%	2.15%
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				4.06%
Senior Notes [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.40%	2.40%
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				2,048
Weighted Average Interest Rate				3.92%
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				2,021
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%	3.30%
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				2,048
Weighted Average Interest Rate				4.38%
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				6.05%	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				2,048
Weighted Average Interest Rate				5.52%
Senior Notes [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.15%	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				2,018
Maturity Date High				2,048
Weighted Average Interest Rate				4.04%
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				6.20%	6.45%
Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[11]			2,018
Maturity Date High	[11]			2,038
Weighted Average Interest Rate				3.14%
Pollution Control Bonds [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.60%	1.54%
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				2,020
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%	1.75%
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	[11]			2,018
Maturity Date High	[11]			2,038
Weighted Average Interest Rate				2.64%
Pollution Control Bonds [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.70%	1.625%
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	[11]			2,018
Maturity Date High	[11]			2,025
Weighted Average Interest Rate				2.49%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.81%	1.75%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.05%	2.75%
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				1.60%
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				1.60%	4.95%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals)
Repayments of Long-term Debt			$ 54
Debt Instrument, Interest Rate, Stated Percentage			1.60%
Due Date			2,019
Notes Payable, Other Payables [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,032
Weighted Average Interest Rate				3.95%
Notes Payable, Other Payables [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.20%	2.03%
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				2,019
Maturity Date High				2,022
Weighted Average Interest Rate				3.30%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.20%	2.03%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.38%	2.19%
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals)
Repayments of Long-term Debt		$ 2	$ 15
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				5.23%
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	[12]			2,018
Maturity Date High	[12]			2,028
Weighted Average Interest Rate				3.65%
Securitization Bonds [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.98%	1.98%
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	[12]			2,018
Maturity Date High	[12]			2,024
Weighted Average Interest Rate				3.95%
Securitization Bonds [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.98%	1.98%
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)
Repayments of Long-term Debt			104
Securitization Bonds [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[12]			2,023
Maturity Date High	[12]			2,028
Weighted Average Interest Rate				3.06%
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)
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	[12]			2,019
Maturity Date High	[12]			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%	2.049%
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)
Repayments of Long-term Debt			23
Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,059
Weighted Average Interest Rate				3.72%
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				3.94%
Other Long Term Debt [Member] | AEP Texas Inc. [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.94%	2.75%
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				3.91%
Other Long Term Debt [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.74%	2.73%
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				3.80%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.66%	2.82%
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				3.70%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.00%	2.584%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.72%	3.00%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,020
Maturity Date High				2,028
Weighted Average Interest Rate				4.03%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.75%	2.925%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.68%	4.28%
Other Long Term Debt [Member] | Transource Energy [Member] | Subsequent Event [Member]
Financing Activities (Textuals)
Proceeds from Issuance of Long-term Debt		$ 3	$ 3
Due Date			2,020
July 2020 [Member]
Financing Activities (Textuals)
Commitment From Bank Conduits To Finance Receivables				$ 125
July 2021 [Member]
Financing Activities (Textuals)
Commitment From Bank Conduits To Finance Receivables				625
Servicing Contracts [Member] | Appalachian Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				7	$ 5.6		$ 6.7
Servicing Contracts [Member] | Indiana Michigan Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				9.2	6.7		7.1
Servicing Contracts [Member] | Ohio Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				26.3	21.7		28.9
Servicing Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				7.9	7		6.2
Servicing Contracts [Member] | Southwestern Electric Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers				$ 8.9	$ 7.2		$ 6.9
[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 SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.
[5]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[6]	Weighted-average interest rate.
[7]	Includes the restrictions of consolidated and non-consolidated subsidiaries.
[8]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[9]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
[10]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
[11]	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.
[12]	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.

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock Based Compensation (Textuals)
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		8,194,046
Reduction in Aggregate Common Shares Authorized Per Share Issued Pursuant to Stock Options or Stock Appreciation Rights		0.286
Performance Units and AEP Career Shares Reinvested Dividends Portion For [Member]
Performance Units
Awarded Units	[1]	80,200	74,600	89,200
Weighted Average Grant Date Fair Value, Granted		$ 70.58	$ 72.35	$ 63.83
Vesting Period	[2]	(c)	(c)	(c)
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 70.58	$ 72.35	$ 63.83
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		70.58	72.35	63.83
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 70.58	$ 72.35	$ 63.83
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]	$ 53.2	$ 79.5	$ 66.5
Actual Tax Benefit Realized	[4]	7.7	18.9	23.3
Total Compensation Cost Capitalized		19.7	$ 26.4	$ 20.8
Stock Based Compensation (Textuals)
Total Unrecognized Compensation Cost Related to Unvested Share-based Compensation Arrangements Granted		$ 60
Weighted-average Period of Unrecognized Compensation Costs (in years)		1.4 years
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 70.41	$ 70.79	$ 64.96
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		11,400	14,800	19,100
Weighted Average Grant Date Fair Value		$ 70.41	$ 70.79	$ 64.96
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		11,400	14,800	19,100
Weighted Average Grant Date Fair Value, Granted		$ 70.41	$ 70.79	$ 64.96
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		11,400	14,800	19,100
Weighted Average Grant Date Fair Value		$ 70.41	$ 70.79	$ 64.96
Stock Based Compensation (Textuals)
Shares/Units, Granted		11,400	14,800	19,100
Number of Years After Termination of Board Service Participant Can Elect to Have Stock Units Paid in Cash		10 years
Restricted Stock Units (RSUs) [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 67.96	$ 65.26	$ 62.88
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		260,000	255,800	242,000
Weighted Average Grant Date Fair Value		$ 67.96	$ 65.26	$ 62.88
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		$ 16.6	$ 16.1	$ 16.4
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	[5]	$ 19.2	$ 20	$ 21
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		529,600
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 62.13
Shares/Units, Granted		260,000	255,800	242,000
Weighted Average Grant Date Fair Value, Granted		$ 67.96	$ 65.26	$ 62.88
Shares/Units, Vested		(277,500)
Weighted Average Grant Date Fair Value, Vested		$ 59.77
Shares/Units, Forfeited		(23,000)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 64.84
Nonvested, Shares/Units, Ending Balance		489,100	529,600
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 66.01	$ 62.13
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		260,000	255,800	242,000
Weighted Average Grant Date Fair Value		$ 67.96	$ 65.26	$ 62.88
Stock Based Compensation (Textuals)
Maximum Contractual Term of Outstanding Restricted Stock Units (in months)		40 months
Shares/Units, Granted		260,000	255,800	242,000
Total Aggregate Intrinsic Value of Nonvested Shares		$ 37
Weighted Average Remaining Contractual Life of Nonvested Shares (in years)		1.65 years
Performance Units [Member]
Performance Units
Awarded Units	[6]	581,400	590,700	597,400
Weighted Average Grant Date Fair Value, Granted		$ 67.21	$ 69.78	$ 62.77
Vesting Period (in years)		3 years	3 years	3 years
Certified Performance Scores and Units Earned
Certified Performance Score		136.70%	164.80%	163.90%
Performance Units Earned		820,780	956,055	1,111,966
Performance Units Manditorily Deferred as AEP Career Shares		11,248	20,213	9,963
Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program		56,826	47,177	51,684
Performance Units to be Paid in Cash		752,706	888,665	1,050,319
Cash Payouts
Cash Payouts for Performance Units		$ 66.9	$ 64.9	$ 62.7
Cash Payouts for AEP Career Share Distributions		$ 0	$ 0	$ 9.1
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 67.21	$ 69.78	$ 62.77
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		67.21	69.78	62.77
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 67.21	$ 69.78	$ 62.77
Stock Based Compensation (Textuals)
Performance Score by HR Committee, Lower Range		0.00%
Performance Score by HR Committee, Higher Range		200.00%
Equity Payouts For Career Share Distributions		$ 5.1	$ 0.4	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	[7]	2 years 10 months 14 days	2 years 10 months 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum		14.77%	15.65%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum		26.72%	27.19%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate		2.34%	1.44%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	[8]	0.00%	0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Weighted Average Volatility Rate		17.90%	19.07%
Performance Units and Reinvested Dividends [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 67.43
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		617,300
Weighted Average Grant Date Fair Value		$ 67.43
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		587,500
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 64.48
Shares/Units, Granted		617,300
Weighted Average Grant Date Fair Value, Granted		$ 67.43
Shares/Units, Vested		0
Weighted Average Grant Date Fair Value, Vested		$ 0
Shares/Units, Forfeited		(33,500)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 65.50
Nonvested, Shares/Units, Ending Balance		1,171,300	587,500
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 66.01	$ 64.48
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		617,300
Weighted Average Grant Date Fair Value		$ 67.43
Stock Based Compensation (Textuals)
Shares/Units, Granted		617,300
[1]	Awarded dividends in 2018 and 2017 were a mix of equity awards and liability awards, and all awarded dividends in 2016 were liability awards.
[2]	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.
[3]	Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.
[4]	In December 2017, Tax Reform modified Section 162(m) of the Internal Revenue Code. Beginning after 2017, AEP can no longer deduct certain compensation expense in excess of $1 million for certain named executive officers. This will reduce the tax benefit going forward.
[5]	Intrinsic value is calculated as market price at exercise date.
[6]	Awarded units in 2018 and 2017 were mezzanine equity awards and awarded units in 2016 were liability awards.
[7]	Period from award date to vesting date.
[8]	Equivalent to reinvesting dividends.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
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		$ 12	10		13
Railcar Maintenance		$ 1.5	1.3		1.7
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		$ 0.7	0.5		0.6
AEP Generating Co To Southwestern Electric Power Co [Member]
Cook Coal Terminal
Railcar Maintenance		3.4	3.5		3.3
AEP Energy Partners, Inc. to AEP Texas Inc. [Member]
Oklaunion PPA between AEP Texas and AEPEP
Oklaunion Purchase Power Agreement		104	64		74
Indiana Michigan Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		2.2	1.4		0.8
Kentucky Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		0.2	0.2		0.1
Ohio Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		2.9	2.4		2.3
Public Service Co of Oklahoma to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		0.3	0.3		0.2
AEP Generating Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		19.9	15.3		14.8
AEP Generation Resources [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		0	0.1		0.3
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1.6	1.2		2
AEP Transmission Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		598.9	568.1	[1]	367.5
Sales and Purchases of Property
Related Party Purchases of Property		18.5	9.1		6.5
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		0
AEP Transmission Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	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		591.4	559.6	[3]	366.1
AEP Transmission Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		7.5	8.5		0
Appalachian Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		181.4	172		142.1
Transmission Agreement
Net Charges from Transmission Agreement		128.3	158.2		103.2
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		35.1	37.2		36.9
Sales and Purchases of Property
Related Party Sales of Property		5.4	3.5		4.5
Related Party Purchases of Property		0.6	0.9		1.5
Appalachian Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		133.2	130.4		126
Appalachian Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Appalachian Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	5.8	1		9.2
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		36.4	34.1		1.3
Appalachian Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		6	6.5		5.6
Indiana Michigan Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		22.1	1.8		26.2
Cost of Purchased Power from Affiliate		237.9	223.9		228.6
Transmission Agreement
Net Charges from Transmission Agreement		91.4	103.8		53
Central Machine Shop
Billings for Services from Central Machine Shop Facility		2.4	2.7		2.9
Sales and Purchases of Property
Related Party Sales of Property		8.2	5		5.2
Related Party Purchases of Property		2	3.5		2.7
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] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0		0
Indiana Michigan Power Co [Member] | Auction Purchases From AEP Energy [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0		0
Indiana Michigan Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0		0
Indiana Michigan Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		237.9	223.9		228.6
Indiana Michigan Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0.1	0		0
Indiana Michigan Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	3.8		0
Indiana Michigan Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	7.1	0		12
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		11.7	(4.4)		12.2
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		3.2	2.4		2
Kentucky Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		4.2	5		5.3
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1.7	1.8		1.5
Ohio Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		21	24.4		17.3
Cost of Purchased Power from Affiliate		135.3	108.5		141.9
Generation Deferrals		0	0		(82.7)
Transmission Agreement
Net Charges from Transmission Agreement		210.1	248.6		143.6
Sales and Purchases of Property
Related Party Sales of Property		10.7	2.9		1.9
Related Party Purchases of Property		2.8	1.6		1.7
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] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	79.7	96.5		110.1
Ohio Power Co [Member] | Auction Purchases From AEP Energy [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	41	5.5		7.7
Ohio Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	14.6	6.5		24.1
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		0
Ohio Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	0	0		0
Ohio Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Ohio Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		3.9	6.2		(2)
Ohio Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		17.1	18.2		19.3
Public Service Co Of Oklahoma [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		5.4	4.3		2.6
Cost of Purchased Power from Affiliate		0	0		3.7
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		65.9	56		19.6
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0.5	1.1		0.5
Sales and Purchases of Property
Related Party Sales of Property		1	1.5		7.5
Related Party Purchases of Property		1.3	0.2		3.2
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] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0		0
Public Service Co Of Oklahoma [Member] | Auction Purchases From AEP Energy [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0		0
Public Service Co Of Oklahoma [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	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		0
Public Service Co Of Oklahoma [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	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		0.9	0		(1.7)
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4.5	4.3		4.3
Southwestern Electric Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		28.4	25.9		24.5
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		10.5	6.6		(19.6)
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0.7	0.8		0.9
Sales and Purchases of Property
Related Party Sales of Property		0.8	0.5		1
Related Party Purchases of Property		0.8	0.4		6.5
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	0		3.7
Southwestern Electric Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	0	0		0
Southwestern Electric Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	(0.2)		(0.2)
Southwestern Electric Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		26.9	24.2		19.4
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1.5	1.9		1.6
Wheeling Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		4.2	5		4.8
AEP Texas Inc. [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		105.2	65.7		75.7
ERCOT Transmission Service Charges
Billings from ETT for ERCOT Wholesale Transmission Services		27	30		29
Oklaunion PPA between AEP Texas and AEPEP
Oklaunion Purchase Power Agreement		22.1	52
Sales and Purchases of Property
Related Party Sales of Property		0.3	0.2		0.3
Related Party Purchases of Property		$ 0.1	0.4		0.7
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		0
AEP Texas Inc. [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	0	0		0
AEP Texas Inc. [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		103.6	63.6		73.9
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		$ 1.6	$ 2.1		$ 1.8
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[2]	Refer to the Ohio Auctions section below for further information regarding these amounts.
[3]	Reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2018USD ($)MW		Dec. 31, 2017USD ($)		Dec. 31, 2016USD ($)
Variable Interest Entities (Textuals)
Securitization Bonds		$ 1,111.4		$ 1,416.5
Securitized Transition Assets		920.6		1,211.2
Redeemable Noncontrolling Interest		$ 69.4		0
Trent and Desert Sky Wind Farms [Member]
Variable Interest Entities (Textuals)
Non-Affiliate Interest		20.10%
AEP Ownership in LLCs		79.90%
Desert Sky and Trent PPA Period		12 years
Redeemable Noncontrolling Interest		$ 69
Trent and Desert Sky Wind Farms [Member] | Current Assets [Member]
ASSETS
Assets		6.8
Trent and Desert Sky Wind Farms [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		348.5
Trent and Desert Sky Wind Farms [Member] | Net Property Plant And Equipment [Member] | Non-Affiliate Contribution [Member]
ASSETS
Assets		84
Trent and Desert Sky Wind Farms [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		0
Trent and Desert Sky Wind Farms [Member] | Total Assets [Member]
ASSETS
Assets		355.3
Trent and Desert Sky Wind Farms [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		8.7
Trent and Desert Sky Wind Farms [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		6.2
Trent and Desert Sky Wind Farms [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		340.4
Trent and Desert Sky Wind Farms [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		355.3
Protected Cell Of Energy Insurance Services, Inc. [Member]
Variable Interest Entities (Textuals)
Insurance Premium Expense to Protected Cell		34		29		$ 28
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Assets [Member]
ASSETS
Assets		177.8		178.7
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		0
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Assets [Member]
ASSETS
Assets		177.9		178.7
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		38.6		36.4
Protected Cell Of Energy Insurance Services, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		85.3		95.2
Protected Cell Of Energy Insurance Services, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		54		47.1
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 177.9		178.7
Transource Energy [Member]
Variable Interest Entities (Textuals)
Debt-to-Total Capitalization Maximum		67.50%
Proceeds from Partnership Contribution		$ 4		5		45
Transource Energy [Member] | Current Assets [Member]
ASSETS
Assets		25.7		17.4
Transource Energy [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		380.3		323.9
Transource Energy [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		1.9		3.1
Transource Energy [Member] | Total Assets [Member]
ASSETS
Assets		407.9		344.4
Transource Energy [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		19.9		12.4
Transource Energy [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		160.3		132
Transource Energy [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		227.7		200
Transource Energy [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 407.9		344.4
AEP Credit, Inc. [Member]
Variable Interest Entities (Textuals)
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		$ 974.2		926.3
AEP Credit, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
AEP Credit, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		6.3		6.4
AEP Credit, Inc. [Member] | Total Assets [Member]
ASSETS
Assets		980.5		932.7
AEP Credit, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		923.5		872
AEP Credit, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		0.8		0.7
AEP Credit, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		56.2		60
AEP Credit, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 980.5		932.7
PATH West Virginia Transmission Co, LLC [Member]
Variable Interest Entities (Textuals)
Percentage of Ownership of Allegheny Series by a Nonaffiliated Company		100.00%
Percentage of Debt 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-WV Refund		$ 11.4
PATH West Virginia Transmission Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
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
As Reported on the Balance Sheet		(1.4)		(2)
Maximum Exposure		(1.4)		(2)
PATH West Virginia Transmission Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		17.4		16.8
Maximum Exposure		$ 17.4		16.8
Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
AEP's Ownership In OVEC		43.47%
Approximate OVEC Generating Capacity (MWs) | MW		2,400
Intercompany Power Agreement End Date		2,040
Outstanding Indebtedness		$ 1,400		1,400
Ohio Valley Electric Corporation [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
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
As Reported on the Balance Sheet		0		0
Maximum Exposure	[1]	604.1		626.3
Ohio Valley Electric Corporation [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		4.4		4.4
Maximum Exposure		$ 608.5		630.7
Parent Company [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
AEP's Ownership In OVEC		39.17%
Great Plains Energy Inc. [Member] | Transource Energy [Member]
Variable Interest Entities (Textuals)
Equity and Voting Ownership Percentage		13.50%
Cleco Power, LLC [Member]
Variable Interest Entities (Textuals)
Percentage of VIE Sales of Lignite Produced		50.00%
AEP Transmission Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		$ 220.4		188.9		131.1
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
As Reported on the Balance Sheet		24.6		25.1
Maximum Exposure		24.6		25.1
Appalachian Power Co [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		272.3		295.9
Securitized Transition Assets		258.7		282.3
Amount Of Power Purchased From OVEC		100.4		101		88
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		295.6		268.8		244.2
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
As Reported on the Balance Sheet		32.2		37
Maximum Exposure		32.2		37
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		272		296
Securitized Transition Assets		259		282
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Assets [Member]
ASSETS
Assets		24.8		22.3
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		261.8	[2]	285.6	[3]
Variable Interest Entities (Textuals)
Intercompany Item Eliminated in Consolidation		3		3
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Assets [Member]
ASSETS
Assets		286.6		307.9
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		28		27.6
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		256.7		278.4
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1.9		1.9
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 286.6		307.9
Appalachian Power Co [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
Power Participation Ratio		15.69%
Outstanding Indebtedness		$ 218		226
Indiana Michigan Power Co [Member]
Variable Interest Entities (Textuals)
Amount Of Power Purchased From OVEC		$ 50.2		50.5		44
Indiana Michigan Power Co [Member] | Rockport Generating Plant (Unit No. 1) [Member]
Variable Interest Entities (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Variable Interest Entities (Textuals)
Payments Made by I&M to DCC Fuel		$ 113		136		101
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Assets [Member]
ASSETS
Assets		77.6		102.5
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		122.3		179.9
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		58.4		86.3
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Assets [Member]
ASSETS
Assets		258.3		368.7
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		77.1		96.5
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		181.2		272.2
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		258.3		368.7
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		173.5		176		147.7
Indiana Michigan Power Co [Member] | Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals)
Billings from VIE		238		224		229
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
As Reported on the Balance Sheet		23.8		26.8
Maximum Exposure		23.8		26.8
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
As Reported on the Balance Sheet		$ 20		23
Indiana Michigan Power Co [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
Power Participation Ratio		7.85%
Outstanding Indebtedness		$ 109		113
Ohio Power Co [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		47.8		94.5
Securitized Transition Assets		12.9		37.7
Amount Of Power Purchased From OVEC		127.5		128.2		111.7
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		214.9		195.7		181.1
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
As Reported on the Balance Sheet		23.9		27.4
Maximum Exposure		23.9		27.4
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		48		95
Securitized Transition Assets		13		38
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Assets [Member]
ASSETS
Assets		29.5		28.7
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		24.2	[4]	71	[5]
Variable Interest Entities (Textuals)
Intercompany Item Eliminated in Consolidation		11		33
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Assets [Member]
ASSETS
Assets		53.7		99.7
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		48.5		47.9
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		3.9		50.5
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		$ 53.7		99.7
Ohio Power Co [Member] | Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
AEP's Ownership In OVEC		4.30%
Power Participation Ratio		19.93%
Outstanding Indebtedness		$ 277		287
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		121.5		114.7		111
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
As Reported on the Balance Sheet		13.2		18.7
Maximum Exposure		13.2		18.7
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Variable Interest Entities (Textuals)
Billings from VIE		152		137		162
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Assets [Member]
ASSETS
Assets		70		56.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		106.9		113.2
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		98.5		90.2
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Assets [Member]
ASSETS
Assets		275.4		259.7
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		31.1		49.1
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		244		211
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		0.3		(0.4)
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		275.4		259.7
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		164.4		150.7		147
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
As Reported on the Balance Sheet		18.4		20.8
Maximum Exposure		18.4		20.8
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Variable Interest Entities (Textuals)
Billings from VIE		$ 58		61		65
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
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
As Reported on the Balance Sheet		14.5		11.8
Maximum Exposure		14.5		11.8
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
As Reported on the Balance Sheet		0		0
Maximum Exposure		167.6		144.3
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
As Reported on the Balance Sheet		22.1		19.4
Maximum Exposure		$ 189.7		163.7
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 1) [Member]
Variable Interest Entities (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member]
Variable Interest Entities (Textuals)
Percentage Interest in Lease		50.00%
Transource Energy [Member]
Variable Interest Entities (Textuals)
Equity and Voting Ownership Percentage		86.50%
AEP Texas Inc. [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		$ 791.2		1,026.1
Securitized Transition Assets		$ 649.1		891.2
Jointly Owned Utility Plant, Proportionate Ownership Share		54.69%
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		$ 791		1,000
Securitized Transition Assets		636.8		869.5
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Current Assets [Member]
ASSETS
Assets		192.8		191.7
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets		0		0
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets		683.5	[6]	923.5	[7]
Variable Interest Entities (Textuals)
Intercompany Item Eliminated in Consolidation		47		54
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Total Assets [Member]
ASSETS
Assets		876.3		1,115.2
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		271.9		260.9
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		586.1		836.1
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		18.3		18.2
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		876.3		1,115.2
AEP Texas Inc. [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		184.3		152.6		$ 142.3
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
As Reported on the Balance Sheet		22.3		24.2
Maximum Exposure		$ 22.3		$ 24.2
[1]	Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $218 million, $109 million and $277 million as of December 31, 2018 and $226 million, $113 million and $287 million as of December 31, 2017, respectively.
[2]	Includes an intercompany item eliminated in consolidation of $3 million.
[3]	Includes an intercompany item eliminated in consolidation of $3 million.
[4]	Includes an intercompany item eliminated in consolidation of $11 million.
[5]	Includes an intercompany item eliminated in consolidation of $33 million.
[6]	Includes an intercompany item eliminated in consolidation of $47 million.
[7]	Includes an intercompany item eliminated in consolidation of $54 million.

Property, Plant and Equipment_3

Property, Plant and Equipment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)		Dec. 31, 2017USD ($)		Dec. 31, 2016USD ($)
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 21,699.9		$ 20,760.5
Property, Plant and Equipment, Transmission	21,531		18,972.5
Property, Plant and Equipment, Distribution	21,195.4		19,868.5
Property, Plant and Equipment, Other	4,265		3,706.3
Property, Plant and Equipment, Construction Work in Progress	4,393.9		4,120.7
Accumulated Depreciation	17,986.1		17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	55,099.1		50,261.5
Asset Retirement Obligations (ARO)
Beginning Balance	2,005.7	[1],[2],[3],[4]	1,934.9	[1],[2],[3],[4]
Accretion Expense	93.7	[1],[2],[3],[4]	90.9	[1],[2],[3],[4]
Liabilities Incurred	0.8	[1],[2],[3],[4]	2.4	[1],[2],[3],[4]
Liabilities Settled	(87)	[1],[2],[3],[4]	(104.5)	[1],[2],[3],[4]
Revisions in Cash Flow Estimates	342.3	[1],[2],[3],[4],[5],[6]	82	[1],[2],[3],[4],[5]
Ending Balance	2,355.5	[1],[2],[3],[4]	2,005.7	[1],[2],[3],[4]	$ 1,934.9	[1],[2],[3],[4]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	132.5		93.7		113.2
Allowance for Borrowed Funds Used During Construction	73.6		48.6		51.7
Jointly-owned Electric Facilities
Utility Plant in Service	3,015.9		3,399.3
Construction Work in Progress	24.6		31.6
Accumulated Depreciation	984.2		1,169.5
Asset Impairments and Other Related Charges	70.6		87.1		2,267.8
Property, Plant and Equipment (Textuals)
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant	1,660		1,300
Fair Value of Legally Restricted Assets	2,160		2,220
AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	352.1		350.7
Property, Plant and Equipment, Transmission	3,683.6		3,053.6
Property, Plant and Equipment, Distribution	4,043.2		3,718.6
Property, Plant and Equipment, Other	727.9		461
Property, Plant and Equipment, Construction Work in Progress	836.2		835.7
Accumulated Depreciation	1,651.2		1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	7,991.8		6,825.1
Asset Retirement Obligations (ARO)
Beginning Balance	26.7	[2],[3]	25.5	[2],[3]
Accretion Expense	1.2	[2],[3]	1.2	[2],[3]
Liabilities Incurred	0	[2],[3]	0	[2],[3]
Liabilities Settled	(0.1)	[2],[3]	(0.1)	[2],[3]
Revisions in Cash Flow Estimates	0.1	[2],[3],[5]	0.1	[2],[3],[5]
Ending Balance	27.9	[2],[3]	26.7	[2],[3]	25.5	[2],[3]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	20		6.8		9.2
Allowance for Borrowed Funds Used During Construction	$ 18.4		6.8		5.9
Jointly-owned Electric Facilities
Percent of Ownership	54.69%
Asset Impairments and Other Related Charges					72.7
AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission	$ 6,515.8		5,319.7
Property, Plant and Equipment, Other	174		126.8
Property, Plant and Equipment, Construction Work in Progress	1,578.3		1,324
Accumulated Depreciation	271.9		152.6	[7]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	7,996.2		6,617.9	[7],[8]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	70.6		49	[7],[9]	52.3
Allowance for Borrowed Funds Used During Construction	26.1		20.2		15.6
Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	6,509.6		6,446.9
Property, Plant and Equipment, Transmission	3,317.7		3,019.9
Property, Plant and Equipment, Distribution	3,989.4		3,763.8
Property, Plant and Equipment, Other	485.8		427.9
Property, Plant and Equipment, Construction Work in Progress	490.2		483
Accumulated Depreciation	4,124.4		3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	10,668.3		10,245.1
Asset Retirement Obligations (ARO)
Beginning Balance	125	[2],[3]	127.1	[2],[3]
Accretion Expense	6.6	[2],[3]	7	[2],[3]
Liabilities Incurred	0	[2],[3]	0	[2],[3]
Liabilities Settled	(17.3)	[2],[3]	(21.7)	[2],[3]
Revisions in Cash Flow Estimates	1.8	[2],[3],[5]	12.6	[2],[3],[5]
Ending Balance	116.1	[2],[3]	125	[2],[3]	127.1	[2],[3]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	13.2		9.2		11.7
Allowance for Borrowed Funds Used During Construction	8.4		5.3		6.3
Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	4,887.2		4,445.9
Property, Plant and Equipment, Transmission	1,576.8		1,504
Property, Plant and Equipment, Distribution	2,249.7		2,069.3
Property, Plant and Equipment, Other	583.8		595.2
Property, Plant and Equipment, Construction Work in Progress	465.3		460.2
Accumulated Depreciation	3,151.6		3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,611.2		6,050.4
Asset Retirement Obligations (ARO)
Beginning Balance	1,321.8	[2],[3],[4]	1,258.1	[2],[3],[4]
Accretion Expense	58.7	[2],[3],[4]	55.9	[2],[3],[4]
Liabilities Incurred	0	[2],[3],[4]	0	[2],[3],[4]
Liabilities Settled	(0.2)	[2],[3],[4]	(0.1)	[2],[3],[4]
Revisions in Cash Flow Estimates	301	[2],[3],[4],[5],[6]	7.9	[2],[3],[4],[5]
Ending Balance	1,681.3	[2],[3],[4]	1,321.8	[2],[3],[4]	1,258.1	[2],[3],[4]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	11.9		11.1		15.3
Allowance for Borrowed Funds Used During Construction	7.4		6.7		7.2
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges	0		0		10.5
Property, Plant and Equipment (Textuals)
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant	1,660		1,300
Fair Value of Legally Restricted Assets	2,160		2,220
Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission	2,544.3		2,419.2
Property, Plant and Equipment, Distribution	4,942.3		4,626.4
Property, Plant and Equipment, Other	574.8		495.9
Property, Plant and Equipment, Construction Work in Progress	432.1		410.1
Accumulated Depreciation	2,218.6		2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,274.9		5,766.8
Asset Retirement Obligations (ARO)
Beginning Balance	1.7	[2]	1.7	[2]
Accretion Expense	0.1	[2]	0.1	[2]
Liabilities Incurred	0	[2]	0	[2]
Liabilities Settled	0	[2]	(0.1)	[2]
Revisions in Cash Flow Estimates	0	[2],[5]	0	[2],[5]
Ending Balance	1.8	[2]	1.7	[2]	1.7	[2]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	9.8		6.4		6
Allowance for Borrowed Funds Used During Construction	5.8		3.8		3.3
Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	1,577		1,577.2
Property, Plant and Equipment, Transmission	892.3		858.8
Property, Plant and Equipment, Distribution	2,572.8		2,445.1
Property, Plant and Equipment, Other	303.5		287.4
Property, Plant and Equipment, Construction Work in Progress	94		111.3
Accumulated Depreciation	1,472.9		1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	3,966.7		3,886.2
Asset Retirement Obligations (ARO)
Beginning Balance	54	[2],[3]	53.4	[2],[3]
Accretion Expense	3.2	[2],[3]	3.1	[2],[3]
Liabilities Incurred	0	[2],[3]	0	[2],[3]
Liabilities Settled	(0.4)	[2],[3]	(0.5)	[2],[3]
Revisions in Cash Flow Estimates	(9.9)	[2],[3],[5]	(2)	[2],[3],[5]
Ending Balance	46.9	[2],[3]	54	[2],[3]	53.4	[2],[3]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	0.4		0.5		6.2
Allowance for Borrowed Funds Used During Construction	0.9		1.1		3.4
Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	4,672.6		4,624.9
Property, Plant and Equipment, Transmission	1,866.9		1,679.8
Property, Plant and Equipment, Distribution	2,178.6		2,095.8
Property, Plant and Equipment, Other	762.7		684.1
Property, Plant and Equipment, Construction Work in Progress	199.3		233.2
Accumulated Depreciation	2,808.3		2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	6,871.8		6,632
Asset Retirement Obligations (ARO)
Beginning Balance	169.2	[1],[2],[3]	156.5	[1],[2],[3]
Accretion Expense	9.1	[1],[2],[3]	8.3	[1],[2],[3]
Liabilities Incurred	0.2	[1],[2],[3]	0	[1],[2],[3]
Liabilities Settled	(11.7)	[1],[2],[3]	(0.3)	[1],[2],[3]
Revisions in Cash Flow Estimates	40	[1],[2],[3],[5]	4.7	[1],[2],[3],[5]
Ending Balance	206.8	[1],[2],[3]	169.2	[1],[2],[3]	156.5	[1],[2],[3]
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction	6		2.4		11
Allowance for Borrowed Funds Used During Construction	4.8		2.1		6.9
Jointly-owned Electric Facilities
Utility Plant in Service	2,893.1		2,878.1
Construction Work in Progress	24.4		25.2
Accumulated Depreciation	914		868.7
Asset Impairments and Other Related Charges	$ 0		$ 33.6		$ 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%	[10],[11],[12]	83.50%	[10],[11],[12]	43.50%
Utility Plant in Service	$ 16.4	[10],[11],[12]	$ 2.1	[10],[11],[12]
Construction Work in Progress	0.2	[10],[11],[12]	4.2	[10],[11],[12]
Accumulated Depreciation	$ 2.4	[10],[11],[12]	$ 0.1	[10],[11],[12]
J.M. Stuart Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership					26.00%
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	$ 336.2	[13]	$ 343.1	[13]
Construction Work in Progress	5.1	[13]	5.3	[13]
Accumulated Depreciation	$ 209.6	[13]	$ 214.2	[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	$ 336.2	[13]	$ 343.1	[13]
Construction Work in Progress	5.1	[13]	5.3	[13]
Accumulated Depreciation	$ 209.6	[13]	$ 214.2	[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	$ 375.1	[14]	$ 364.8	[14]
Construction Work in Progress	1.6	[14]	8.9	[14]
Accumulated Depreciation	$ 88.9	[14]	$ 81.6	[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	$ 375.1	[14]	$ 364.8	[14]
Construction Work in Progress	1.6	[14]	8.9	[14]
Accumulated Depreciation	$ 88.9	[14]	$ 81.6	[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	$ 591.3	[14]	$ 589.8	[14]
Construction Work in Progress	16.6	[14]	7.8	[14]
Accumulated Depreciation	$ 418	[14]	$ 406.3	[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	$ 591.3	[14]	$ 589.8	[14]
Construction Work in Progress	16.6	[14]	7.8	[14]
Accumulated Depreciation	$ 418	[14]	$ 406.3	[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	$ 106.4	[15]	$ 456.4	[15]
Construction Work in Progress	0	[15]	1.9	[15]
Accumulated Depreciation	$ 67.8	[15]	$ 254.6	[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]	54.70%
Utility Plant in Service	$ 352.1	[15]	$ 350.7	[15]
Construction Work in Progress	0.2	[15]	1.3	[15]
Accumulated Depreciation	$ 218.6	[15]	$ 194.1	[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	$ 106.4	[15]	$ 105.7	[15]
Construction Work in Progress	0	[15]	0.6	[15]
Accumulated Depreciation	67.8	[15]	$ 60.5	[15]
Turk Generating Plant [Member]
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges	$ 15
Turk Generating Plant [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	73.30%	[14],[16]	73.30%	[14],[16]
Utility Plant in Service	$ 1,590.5	[14],[16]	$ 1,580.4	[14],[16]
Construction Work in Progress	1.1	[14],[16]	3.2	[14],[16]
Accumulated Depreciation	197.5	[14],[16]	$ 166.6	[14],[16]
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],[16]
Utility Plant in Service	$ 1,590.5	[14],[16]	$ 1,580.4	[14],[16]
Construction Work in Progress	1.1	[14],[16]	3.2	[14],[16]
Accumulated Depreciation	$ 197.5	[14],[16]	$ 166.6	[14],[16]
Jointly Owned Electricity Transmission and Distribution System [Member]
Jointly-owned Electric Facilities
Percent of Ownership				[17]
Utility Plant in Service			$ 62.7	[18]
Construction Work in Progress			0.3	[18]
Accumulated Depreciation			$ 46.1	[18]
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%	[19],[20],[21]	50.00%	[19],[20],[21]
Utility Plant in Service	$ 1,108.7	[19],[20],[21]	$ 1,093.9	[19],[20],[21]
Construction Work in Progress	50.2	[19],[20],[21]	28.2	[19],[20],[21]
Accumulated Depreciation	$ 514.1	[19],[20],[21]	562.6	[19],[20],[21]
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
Percentage Interest in Lease	50.00%
Regulated Operation [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 20,989.1	[22]	20,406.5	[22]
Property, Plant and Equipment, Transmission	21,500.5		18,942.3
Property, Plant and Equipment, Distribution	21,192.8		19,865.9
Property, Plant and Equipment, Other	3,770.8		3,224.8
Property, Plant and Equipment, Construction Work in Progress	4,352.6	[22]	3,972.6	[22]
Accumulated Depreciation	17,743.1		16,906.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 54,062.7		$ 49,505.4
Regulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	132 years		132 years		132 years
Depreciable Life Ranges - Transmission	81 years		100 years		100 years
Depreciable Life Ranges - Distribution	78 years		156 years		156 years
Depreciable Life Ranges - Other	75 years		84 years		84 years
Regulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	20 years		20 years		35 years
Depreciable Life Ranges - Transmission	15 years		15 years		15 years
Depreciable Life Ranges - Distribution	7 years		5 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	4.00%		3.70%		4.00%
Regulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.40%		2.30%		2.10%
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%		1.60%		1.50%
Regulated Operation [Member] | Distribution [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.60%		3.70%		3.70%
Regulated Operation [Member] | Distribution [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.70%		2.60%
Regulated Operation [Member] | Other Property Class [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	9.80%		9.20%		8.60%
Regulated Operation [Member] | Other Property Class [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.30%		3.10%
Regulated Operation [Member] | AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 0		$ 0
Property, Plant and Equipment, Transmission	3,683.6		3,053.6
Property, Plant and Equipment, Distribution	4,043.2		3,718.6
Property, Plant and Equipment, Other	724.6		457.6
Property, Plant and Equipment, Construction Work in Progress	836		834.4
Accumulated Depreciation	1,431.2		1,399.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 7,856.2		$ 6,664.8
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%		1.70%		1.80%
Regulated Operation [Member] | AEP Texas Inc. [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.60%		3.60%		3.30%
Regulated Operation [Member] | AEP Texas Inc. [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	6.00%		8.70%		8.30%
Regulated Operation [Member] | AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 0		$ 0	[8]
Property, Plant and Equipment, Transmission	6,515.8		5,319.7	[8]
Property, Plant and Equipment, Distribution	0		0	[8]
Property, Plant and Equipment, Other	172.6		125.4	[8]
Property, Plant and Equipment, Construction Work in Progress	1,578.3		1,324	[8]
Accumulated Depreciation	271.9		152.6	[8]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 7,994.8		$ 6,616.5	[8]
Regulated Operation [Member] | AEP Transmission Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission	75 years		100 years		100 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	1.90%		1.70%		1.60%
Regulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 6,509.6		$ 6,446.9
Property, Plant and Equipment, Transmission	3,317.7		3,019.9
Property, Plant and Equipment, Distribution	3,989.4		3,763.8
Property, Plant and Equipment, Other	457.4		399.5
Property, Plant and Equipment, Construction Work in Progress	490.2		483
Accumulated Depreciation	4,118.9		3,891.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 10,645.4		$ 10,222
Regulated Operation [Member] | Appalachian Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	112 years		112 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%		1.60%		1.50%
Regulated Operation [Member] | Appalachian Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.60%		3.70%		3.70%
Regulated Operation [Member] | Appalachian Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	7.40%		6.50%		6.00%
Regulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 4,887.2		$ 4,445.9
Property, Plant and Equipment, Transmission	1,576.8		1,504
Property, Plant and Equipment, Distribution	2,249.7		2,069.3
Property, Plant and Equipment, Other	543.1		552.3
Property, Plant and Equipment, Construction Work in Progress	465.3		460.2
Accumulated Depreciation	3,139.4		3,011.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,582.7		$ 6,020
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	73 years		75 years		75 years
Depreciable Life Ranges - Distribution	75 years		70 years		70 years
Depreciable Life Ranges - Other	50 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		20 years		59 years
Depreciable Life Ranges - Transmission	50 years		50 years		50 years
Depreciable Life Ranges - Distribution	9 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	3.40%		2.40%		2.40%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	1.80%		1.70%		1.70%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.10%		2.70%		2.80%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	8.90%		8.40%		8.60%
Regulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 0		$ 0
Property, Plant and Equipment, Transmission	2,544.3		2,419.2
Property, Plant and Equipment, Distribution	4,942.3		4,626.4
Property, Plant and Equipment, Other	563.7		485.5
Property, Plant and Equipment, Construction Work in Progress	432.1		410.1
Accumulated Depreciation	2,217.7		2,183.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,264.7		$ 5,757.3
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	65 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	14 years		5 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	3.00%		2.80%		2.80%
Regulated Operation [Member] | Ohio Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	6.30%		6.20%		5.90%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 1,577		$ 1,577.2
Property, Plant and Equipment, Transmission	892.3		858.8
Property, Plant and Equipment, Distribution	2,572.8		2,445.1
Property, Plant and Equipment, Other	298.1		282
Property, Plant and Equipment, Construction Work in Progress	94		111.3
Accumulated Depreciation	1,472.1		1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 3,962.1		$ 3,880.8
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	75 years		85 years		85 years
Depreciable Life Ranges - Transmission	75 years		100 years		100 years
Depreciable Life Ranges - Distribution	78 years		156 years		156 years
Depreciable Life Ranges - Other	64 years		84 years		84 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		45 years
Depreciable Life Ranges - Distribution	15 years		27 years		27 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	2.90%		2.40%		2.40%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.20%		2.20%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.90%		2.70%		2.70%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	6.30%		7.40%		6.40%
Regulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	$ 4,672.6	[22]	$ 4,624.9	[22]
Property, Plant and Equipment, Transmission	1,866.9		1,679.8
Property, Plant and Equipment, Distribution	2,178.6		2,095.8
Property, Plant and Equipment, Other	485.2		416.8
Property, Plant and Equipment, Construction Work in Progress	194.7	[22]	220.7	[22]
Accumulated Depreciation	2,633.5		2,520.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 6,764.5		$ 6,517.5
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		73 years		70 years
Depreciable Life Ranges - Distribution	70 years		70 years		65 years
Depreciable Life Ranges - Other	55 years		55 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	2.40%		2.30%		2.10%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.20%		2.30%		2.20%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.70%		2.70%		2.60%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	8.00%		7.20%		6.80%
Unregulated Operation [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 1,036.4		$ 756.1
Unregulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	59 years		66 years		66 years
Depreciable Life Ranges - Transmission	40 years		40 years		55 years
Depreciable Life Ranges - Distribution	40 years		40 years		50 years
Depreciable Life Ranges - Other	50 years	[23]	50 years	[23]	50 years	[23]
Unregulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation	15 years		15 years		40 years
Depreciable Life Ranges - Transmission					43 years
Depreciable Life Ranges - Distribution					40 years
Depreciable Life Ranges - Other	5 years	[23]	5 years	[23]	5 years	[23]
Unregulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	22.30%		5.10%		17.20%
Unregulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	3.40%		2.40%		2.80%
Unregulated Operation [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.40%		0.20%		2.30%
Unregulated Operation [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	2.30%		2.30%		1.30%
Unregulated Operation [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate	16.30%		12.10%		9.10%
Unregulated Operation [Member] | AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 135.6		$ 160.3
Unregulated Operation [Member] | AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	1.4		1.4	[8]
Unregulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	22.9		23.1
Unregulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	28.5		30.4
Unregulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	10.2		9.5
Unregulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	4.6		5.4
Unregulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	$ 107.3		114.5
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
Generation and Marketing [Member]
Depreciation, Depletion and Amortization
Accumulated Depreciation	$ 47		75
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	846.3		569.6
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges	$ 47.7		$ 53.5		$ 2,257.3
Generation and Marketing [Member] | Wm. H. Zimmer Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership					25.40%
[1]	Includes ARO related to Sabine and DHLC.
[2]	Includes ARO related to asbestos removal.
[3]	Includes ARO related to ash disposal facilities.
[4]	Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.66 billion and $1.30 billion as of December 31, 2018 and 2017, respectively.
[5]	Primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.
[6]	Revision for Cook Plant related to a new third-party study, which impacted the ARO liability for changes of estimated cash flows and application of a new discount rate.
[7]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[8]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[9]	The amount presented reflects the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[10]	Conesville Generating Station, Unit 4 was impaired as of September 30, 2016. See the “Impairments” section of Note 7.
[11]	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%.
[12]	Operated by AGR.
[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]	In accordance with the 2017 CCD Transmission Asset Exchange Agreement between OPCo, Dayton Power & Light Company and Duke Energy Ohio, Inc., the parties agreed to an exchange and transfer of jointly owned transmission assets in order to eliminate the joint ownership of these assets. The asset exchange closed on June 30, 2018, ending the joint ownership of these transmission assets.
[19]	AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.
[20]	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.
[21]	Operated by I&M.
[22]	AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
[23]	SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in Carrying Amount of Goodwill
Goodwill	$ 52.5	$ 52.5	$ 52.5
Impairment Losses	0	0
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

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Disaggregation of Revenue

Revenue from Contracts with Customers

$ 16,195.7

$ 15,424.9

$ 16,380.1

Total Revenues

$ 3,801.1

$ 4,333.1

$ 4,013.2

$ 4,048.3

$ 3,810.4

$ 4,104.7

$ 3,576.5

$ 3,933.3

16,195.7

15,424.9

16,380.1

Revenue, Performance Obligation

Fixed Performance Obligations

1,523.2

1,523.2

Revenue Textuals

Revenue from Related Parties

0

0

0

2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

920.7

920.7

2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

173.7

173.7

2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

162.5

162.5

After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

266.3

266.3

Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

12,327.8

Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

5,941

Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

3,479.8

Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,684.7

Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

222.3

Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

3,337.7

Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,353

Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

1,218.2

Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

766.5

Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

453

Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

16,118.5

Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

77.2

Alternative [Member]

Disaggregation of Revenue

Total Revenues

(45.8)

Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

268.6

229.5

180.7

Total Revenues

[3]

123

AEP Texas Inc. [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,493

Total Revenues

402

433.4

388.3

371.6

374.1

431.2

389.5

343.6

1,595.3

1,538.4

1,461.4

Revenue, Performance Obligation

Fixed Performance Obligations

332.8

332.8

Current Assets

Affiliated Companies - Contracts with Customers

15

12.3

15

12.3

Revenue Textuals

Revenue from Related Parties

105.2

65.7

75.7

AEP Texas Inc. [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

332.8

332.8

AEP Texas Inc. [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

AEP Texas Inc. [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

AEP Texas Inc. [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

AEP Texas Inc. [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,151

AEP Texas Inc. [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

578.9

AEP Texas Inc. [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

436.2

AEP Texas Inc. [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

110

AEP Texas Inc. [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

25.9

AEP Texas Inc. [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

313.4

AEP Texas Inc. [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

0

AEP Texas Inc. [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

313.4

AEP Texas Inc. [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

28.6

AEP Texas Inc. [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

102.3

AEP Texas Inc. [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(1.3)

AEP Texas Inc. [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

3.8

2.4

2.5

Total Revenues

[6]

103.6

AEP Transmission Co [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

832

Total Revenues

189.9

[7]

194.4

[7]

200.1

[7]

191.7

[7]

159.2

165.6

229.4

152.7

776.1

706.9

[8]

478

Revenue, Performance Obligation

Fixed Performance Obligations

893.6

893.6

Current Assets

Affiliated Companies - Contracts with Customers

61

93.2

61

93.2

Revenue Textuals

Revenue from Related Parties

598.9

568.1

[8]

367.5

AEP Transmission Co [Member] | Short-term Contract with Customer [Member]

Current Assets

Affiliated Companies - Contracts with Customers

58.6

47.1

58.6

47.1

AEP Transmission Co [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

893.6

893.6

AEP Transmission Co [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

AEP Transmission Co [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

AEP Transmission Co [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

AEP Transmission Co [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Co [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Co [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Co [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Co [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Co [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[9]

816.9

AEP Transmission Co [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[9]

0

AEP Transmission Co [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

816.9

Revenue Textuals

Revenue from Related Parties

646

AEP Transmission Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

15.1

AEP Transmission Co [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

(55.9)

AEP Transmission Co [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(55.9)

AEP Transmission Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0.2

0.8

[8]

0.1

Total Revenues

[6]

0

AEP Transmission Co [Member] | Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

177

138

[8]

110.4

Appalachian Power Co [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,993.2

Total Revenues

718.1

762

667

820.4

746.8

719.3

675.3

792.8

2,967.5

2,934.2

3,001.2

Revenue, Performance Obligation

Fixed Performance Obligations

200.2

200.2

Current Assets

Affiliated Companies - Contracts with Customers

73.4

69.3

73.4

69.3

Revenue Textuals

Revenue from Related Parties

181.4

172

142.1

Appalachian Power Co [Member] | Short-term Contract with Customer [Member]

Current Assets

Affiliated Companies - Contracts with Customers

52.5

35.6

52.5

35.6

Appalachian Power Co [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

144.8

144.8

Appalachian Power Co [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

32.2

32.2

Appalachian Power Co [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

23.2

23.2

Appalachian Power Co [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Appalachian Power Co [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,604.8

Appalachian Power Co [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,342.6

Appalachian Power Co [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

582.4

Appalachian Power Co [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

602.4

Appalachian Power Co [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

77.4

Appalachian Power Co [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

333.1

Appalachian Power Co [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

250.4

Revenue Textuals

Revenue from Related Parties

134

Appalachian Power Co [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

82.7

Appalachian Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

55.3

Appalachian Power Co [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

(25.7)

Appalachian Power Co [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(23.8)

Appalachian Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

9

13.2

11.7

Total Revenues

[6]

(1.9)

Indiana Michigan Power Co [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,381

Total Revenues

574.5

629.7

589.7

576.8

535.7

557.7

467.3

560.5

2,370.7

2,121.2

2,167.6

Revenue, Performance Obligation

Fixed Performance Obligations

31.4

31.4

Current Assets

Affiliated Companies - Contracts with Customers

75

50

75

50

Revenue Textuals

Revenue from Related Parties

22.1

1.8

26.2

Indiana Michigan Power Co [Member] | Short-term Contract with Customer [Member]

Current Assets

Affiliated Companies - Contracts with Customers

35.3

15.1

35.3

15.1

Indiana Michigan Power Co [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

25.6

25.6

Indiana Michigan Power Co [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

2.9

2.9

Indiana Michigan Power Co [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

2.9

2.9

Indiana Michigan Power Co [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Indiana Michigan Power Co [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,787.8

Indiana Michigan Power Co [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

730

Indiana Michigan Power Co [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

490.3

Indiana Michigan Power Co [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

560.3

Indiana Michigan Power Co [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

7.2

Indiana Michigan Power Co [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

493.6

Indiana Michigan Power Co [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

470.5

Indiana Michigan Power Co [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

23.1

Indiana Michigan Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

99.6

Indiana Michigan Power Co [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

(10.3)

Indiana Michigan Power Co [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(2.1)

Indiana Michigan Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

12.6

14.3

17

Total Revenues

[6]

(8.2)

Revenue Textuals

Revenue from Related Parties

70

Ohio Power Co [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

3,079.9

Total Revenues

745.4

778.3

748.8

790.9

731.9

742

663.9

746.1

3,063.4

2,883.9

2,953.9

Revenue, Performance Obligation

Fixed Performance Obligations

65.4

65.4

Current Assets

Affiliated Companies - Contracts with Customers

70.8

70.2

70.8

70.2

Revenue Textuals

Revenue from Related Parties

21

24.4

17.3

Ohio Power Co [Member] | Short-term Contract with Customer [Member]

Current Assets

Affiliated Companies - Contracts with Customers

46.1

26.1

46.1

26.1

Ohio Power Co [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

65.4

65.4

Ohio Power Co [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Ohio Power Co [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Ohio Power Co [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Ohio Power Co [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,845.3

Ohio Power Co [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,611.5

Ohio Power Co [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

835.7

Ohio Power Co [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

385.2

Ohio Power Co [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

12.9

Ohio Power Co [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

58.5

Ohio Power Co [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

0

Ohio Power Co [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

58.5

Ohio Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

176.1

Ohio Power Co [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

(16.5)

Ohio Power Co [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(20.8)

Ohio Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

8.6

6

6.5

Total Revenues

[6]

4.3

Public Service Co Of Oklahoma [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,536.4

Total Revenues

330.8

481.4

398.3

336.8

335.6

442.8

344.7

304.1

1,547.3

1,427.2

1,249.8

Revenue, Performance Obligation

Fixed Performance Obligations

17.3

17.3

Current Assets

Affiliated Companies - Contracts with Customers

26.2

32.9

26.2

32.9

Revenue Textuals

Revenue from Related Parties

5.4

4.3

2.6

Public Service Co Of Oklahoma [Member] | Short-term Contract with Customer [Member]

Current Assets

Affiliated Companies - Contracts with Customers

12.4

6.1

12.4

6.1

Public Service Co Of Oklahoma [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

17.3

17.3

Public Service Co Of Oklahoma [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Public Service Co Of Oklahoma [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Public Service Co Of Oklahoma [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Public Service Co Of Oklahoma [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,440.8

Public Service Co Of Oklahoma [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

659

Public Service Co Of Oklahoma [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

404.4

Public Service Co Of Oklahoma [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

294.1

Public Service Co Of Oklahoma [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

83.3

Public Service Co Of Oklahoma [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

76.5

Public Service Co Of Oklahoma [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

36.3

Public Service Co Of Oklahoma [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

40.2

Public Service Co Of Oklahoma [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

19.1

Public Service Co Of Oklahoma [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

10.9

Public Service Co Of Oklahoma [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

10.9

Public Service Co Of Oklahoma [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

4.3

5.4

4.4

Total Revenues

[6]

0

Southwestern Electric Power Co [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,817

Total Revenues

410.1

$ 535.3

$ 457.1

$ 419.4

436.3

$ 517.6

$ 424.7

$ 401.3

1,821.9

1,779.9

1,748

Revenue, Performance Obligation

Fixed Performance Obligations

35.2

35.2

Current Assets

Affiliated Companies - Contracts with Customers

28.8

30.2

28.8

30.2

Revenue Textuals

Revenue from Related Parties

28.4

25.9

24.5

Southwestern Electric Power Co [Member] | Short-term Contract with Customer [Member]

Current Assets

Affiliated Companies - Contracts with Customers

16.3

$ 11

16.3

11

Southwestern Electric Power Co [Member] | 2019 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

35.2

35.2

Southwestern Electric Power Co [Member] | 2020-2021 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Southwestern Electric Power Co [Member] | 2022-2023 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

0

0

Southwestern Electric Power Co [Member] | After 2024 [Member]

Revenue, Performance Obligation

Fixed Performance Obligations

$ 0

0

Southwestern Electric Power Co [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,467.8

Southwestern Electric Power Co [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

641.5

Southwestern Electric Power Co [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

491.9

Southwestern Electric Power Co [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

325.8

Southwestern Electric Power Co [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

8.6

Southwestern Electric Power Co [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

325.2

Southwestern Electric Power Co [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

216.8

Southwestern Electric Power Co [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[4]

108.4

Southwestern Electric Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[5]

24

Southwestern Electric Power Co [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

4.9

Southwestern Electric Power Co [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

4.9

Southwestern Electric Power Co [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1.6

1.9

2

Total Revenues

[6]

0

Consolidation Eliminations [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

0

0

Total Revenues

(942.4)

(949)

(738.1)

Revenue Textuals

Revenue from Related Parties

(942.4)

(949)

(738.1)

Consolidation Eliminations [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Consolidation Eliminations [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Consolidation Eliminations [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Consolidation Eliminations [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Consolidation Eliminations [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Consolidation Eliminations [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

(963.1)

Consolidation Eliminations [Member] | Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Consolidation Eliminations [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

(226)

Consolidation Eliminations [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

(737.1)

Consolidation Eliminations [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

(32)

Consolidation Eliminations [Member] | Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

(995.1)

Consolidation Eliminations [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

52.7

Consolidation Eliminations [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

52.7

Consolidation Eliminations [Member] | Other Revenues [Member]

Disaggregation of Revenue

Total Revenues

[3]

0

Consolidation Eliminations [Member] | AEP Transmission Co [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

0

0

Total Revenues

0

0

0

Revenue Textuals

Revenue from Related Parties

0

0

0

Vertically Integrated Utilities [Member]

Disaggregation of Revenue

Total Revenues

9,645.5

9,192

9,091.9

Revenue Textuals

Revenue from Related Parties

88.8

96.9

79.5

Vertically Integrated Utilities [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

8,331.5

Vertically Integrated Utilities [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

3,751.8

Vertically Integrated Utilities [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,206.4

Vertically Integrated Utilities [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,190.2

Vertically Integrated Utilities [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

183.1

Vertically Integrated Utilities [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,182

Vertically Integrated Utilities [Member] | Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Vertically Integrated Utilities [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

899.8

Vertically Integrated Utilities [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

282.2

Vertically Integrated Utilities [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

158.4

Vertically Integrated Utilities [Member] | Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

9,671.9

Vertically Integrated Utilities [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

(26.4)

Vertically Integrated Utilities [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(15.9)

Vertically Integrated Utilities [Member] | Other Revenues [Member]

Disaggregation of Revenue

Total Revenues

[3]

(10.5)

Transmission And Distribution Utilities [Member]

Disaggregation of Revenue

Total Revenues

4,653.1

4,419.3

4,422.4

Revenue Textuals

Revenue from Related Parties

100.8

90.4

94.1

Transmission And Distribution Utilities [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

3,996.3

Transmission And Distribution Utilities [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

2,189.2

Transmission And Distribution Utilities [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,273.4

Transmission And Distribution Utilities [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

494.5

Transmission And Distribution Utilities [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

39.2

Transmission And Distribution Utilities [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

372.1

Transmission And Distribution Utilities [Member] | Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Transmission And Distribution Utilities [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

0

Transmission And Distribution Utilities [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

372.1

Transmission And Distribution Utilities [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

204.6

Transmission And Distribution Utilities [Member] | Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

4,573

Transmission And Distribution Utilities [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

80.1

Transmission And Distribution Utilities [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(22.2)

Transmission And Distribution Utilities [Member] | Other Revenues [Member]

Disaggregation of Revenue

Total Revenues

[3]

102.3

AEP Transmission Holdco [Member]

Disaggregation of Revenue

Total Revenues

804.1

AEP Transmission Holdco [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Holdco [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Holdco [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Holdco [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Holdco [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Holdco [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

849.3

AEP Transmission Holdco [Member] | Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

AEP Transmission Holdco [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

0

AEP Transmission Holdco [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

849.3

Revenue Textuals

Revenue from Related Parties

643

AEP Transmission Holdco [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

15.2

AEP Transmission Holdco [Member] | Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

864.5

AEP Transmission Holdco [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

(60.4)

AEP Transmission Holdco [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

(60.4)

AEP Transmission Holdco [Member] | Other Revenues [Member]

Disaggregation of Revenue

Total Revenues

[3]

0

Generation and Marketing [Member]

Disaggregation of Revenue

Total Revenues

1,940.3

1,875.1

2,986

Revenue Textuals

Revenue from Related Parties

122.2

103.7

127.3

Generation and Marketing [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Generation and Marketing [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Generation and Marketing [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Generation and Marketing [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Generation and Marketing [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Generation and Marketing [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,897.4

Generation and Marketing [Member] | Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,353

Generation and Marketing [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

544.4

Revenue Textuals

Revenue from Related Parties

121

Generation and Marketing [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

0

Generation and Marketing [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

20.6

Generation and Marketing [Member] | Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

1,918

Generation and Marketing [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

22.3

Generation and Marketing [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

0

Generation and Marketing [Member] | Other Revenues [Member]

Disaggregation of Revenue

Total Revenues

[3]

22.3

Other Segments [Member]

Disaggregation of Revenue

Total Revenues

[10]

95.1

120.8

105.1

Revenue Textuals

Revenue from Related Parties

[10]

75.1

69.7

70.3

Other Segments [Member] | Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Residential [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Commercial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Industrial [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Other Retail [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Wholesale and Competitive [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Marketing, Competitive Retail and Renewable [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

0

Other Segments [Member] | Wholesale Generation [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[1]

0

Other Segments [Member] | Wholesale Transmission [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[2]

0

Other Segments [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[3]

86.2

Other Segments [Member] | Affiliated and Nonaffiliated [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

86.2

Other Segments [Member] | Alternative and Other [Member]

Disaggregation of Revenue

Total Revenues

8.9

Other Segments [Member] | Alternative [Member]

Disaggregation of Revenue

Total Revenues

0

Other Segments [Member] | Other Revenues [Member]

Disaggregation of Revenue

Revenue from Contracts with Customers

[10]

20

$ 51.1

$ 34.8

Total Revenues

[3]

$ 8.9

[1]

Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $121 million. The remaining affiliated amounts were immaterial.

[2]

Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $643 million. The remaining affiliated amounts were immaterial.

[3]

Amounts include affiliated and nonaffiliated revenues.

[4]

Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $646 million. The remaining affiliated amounts were immaterial.

[5]

Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $70 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

[6]

Amounts include affiliated and nonaffiliated revenues.

[7]

The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1.

[8]

The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

[9]

Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $134 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

[10]

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 other nonallocated costs.

Unaudited Quarterly Financial_3

Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 3,801.1		$ 4,333.1		$ 4,013.2		$ 4,048.3		$ 3,810.4		$ 4,104.7		$ 3,576.5		$ 3,933.3		$ 16,195.7	$ 15,424.9		$ 16,380.1
Operating Income (Loss)	551.1		668.6		757		706		730.9	[1]	975.1	[1]	733.3	[1]	1,085.7	[1]	2,682.7	3,525		1,163.9
Net Income (Loss)	364.8		579.7		530.1		456.7		401.8		556.7		376.2		594.2		1,931.3	1,928.9		618
Amounts Attributable to Common Shareholders
Earnings (Loss) Attributable To Common Shareholders	$ 363.4		$ 577.6		$ 528.4		$ 454.4		$ 400.7		$ 544.7		$ 375		$ 592.2		$ 1,923.8	$ 1,912.6		$ 610.9
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 0.74	[2]	$ 1.17	[2]	$ 1.07	[2]	$ 0.92	[2]	$ 0.81	[2]	$ 1.11	[2]	$ 0.76	[2]	$ 1.20	[2]	$ 3.90	$ 3.89		$ 1.25
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations																	0	0		(0.01)
Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders																	3.90	3.89		1.24
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 0.74	[2]	$ 1.17	[2]	$ 1.07	[2]	$ 0.92	[2]	$ 0.81	[2]	$ 1.10	[2]	$ 0.76	[2]	$ 1.20	[2]	3.90	3.88		1.25
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations																	0	0		(0.01)
Total Diluted Earnings (Loss) Per Share Attributable to AEP Common Shareholders																	$ 3.90	$ 3.88		$ 1.24
AEP Texas Inc. [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 402		$ 433.4		$ 388.3		$ 371.6		$ 374.1		$ 431.2		$ 389.5		$ 343.6		$ 1,595.3	$ 1,538.4		$ 1,461.4
Operating Income (Loss)	84.3		94		86.2		81.8		96.2	[1]	128.8	[1]	108.8	[1]	82.3	[1]	346.3	416.1		376.3
Net Income (Loss)	60.2		57.8		46.5		46.8		163.9		64.3		49		33.3		211.3	310.5		146.6
AEP Transmission Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	189.9	[3]	194.4	[3]	200.1	[3]	191.7	[3]	159.2		165.6		229.4		152.7		776.1	706.9	[4]	478
Operating Income (Loss)	91.5	[3]	97	[3]	110.5	[3]	111.1	[3]	83.5	[1]	93.6	[1]	165.4	[1]	90.4	[1]	410.1	432.9		280.1
Net Income (Loss)	71.7	[3]	78.1	[3]	82	[3]	84.1	[3]	47.7		58.6		107.4		57		315.9	270.7	[4],[5]	192.7
Appalachian Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	718.1		762		667		820.4		746.8		719.3		675.3		792.8		2,967.5	2,934.2		3,001.2
Operating Income (Loss)	108.1		49.8		132.6		193		173.6	[1]	171.7	[1]	126.1	[1]	218.9	[1]	483.5	690.3		738.3
Net Income (Loss)	77.8		87.1		77.4		125.5		82.6		86		52.1		110.6		367.8	331.3		369.1
Indiana Michigan Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	574.5		629.7		589.7		576.8		535.7		557.7		467.3		560.5		2,370.7	2,121.2		2,167.6
Operating Income (Loss)	52.2		110.2		117.4		97.4		82.8	[1]	113.6	[1]	33.6	[1]	117.2	[1]	377.2	347.2		374.3
Net Income (Loss)	29.7		72.7		94.7		64.2		42.9		64.9		10.5		68.4		261.3	186.7		239.9
Ohio Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	745.4		778.3		748.8		790.9		731.9		742		663.9		746.1		3,063.4	2,883.9		2,953.9
Operating Income (Loss)	118.2		79.9		104.4		117.3		144.2	[1]	153.4	[1]	118.5	[1]	149.6	[1]	419.8	565.7		504.1
Net Income (Loss)	88.4		88.7		68.8		79.6		92.8		82.6		62.3		86.2		325.5	323.9		282.2
Public Service Co Of Oklahoma [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	330.8		481.4		398.3		336.8		335.6		442.8		344.7		304.1		1,547.3	1,427.2		1,249.8
Operating Income (Loss)	2.9		78.5		57.2		3.9		20.4	[1]	85.9	[1]	45.3	[1]	19.9	[1]	142.5	171.5		195.6
Net Income (Loss)	(6.6)		60.4		36.6		(7.2)		0.6		46.2		20.4		4.8		83.2	72		100
Southwestern Electric Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	410.1		535.3		457.1		419.4		436.3		517.6		424.7		401.3		1,821.9	1,779.9		1,748
Operating Income (Loss)	38.5		127.1		70.5		41.6		41.1	[1]	136	[1]	74.1	[1]	52.8	[1]	277.7	304		317.4
Net Income (Loss)	10.5		89.6		38.7		13.4		11		84.1		25.1		17.3		152.2	137.5		169.7
Amounts Attributable to Common Shareholders
Earnings (Loss) Attributable To Common Shareholders	$ 9.6		$ 88.2		$ 37.6		$ 11.8		$ 10.8		$ 73.1		$ 24.5		$ 16.3		$ 147.2	$ 124.7		$ 165.6
[1]	Amounts reflect the adoption of ASU 2017-07 “Compensation - Retirement Benefits”. See Note 2 - New Accounting Pronouncements for additional information.
[2]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[3]	The amounts presented for the Quarterly Periods Ended March 31, 2018 and June 30, 2018 reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously issued Financial Statement” section of Note 1.
[4]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
[5]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.