Indiana Michigan Power 10-Q 24 Oct 19 2019 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Oct. 24, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	1-3525
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	13-4922640
Entity Address, Address Line One	1 Riverside Plaza,
Entity Address, City or Town	Columbus,
Entity Address, State or Province	OH
Entity Address, Postal Zip Code	43215-2373
City Area Code	(614)
Local Phone Number	716-1000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		493,951,812
Entity Central Index Key	0000004904
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
AEP Texas Inc. [Member]
Entity Information [Line Items]
Entity File Number	333-221643
Entity Registrant Name	AEP TEXAS INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0007707
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		100
Entity Central Index Key	0001721781
AEP Transmission Co [Member]
Entity Information [Line Items]
Entity File Number	333-217143
Entity Registrant Name	AEP TRANSMISSION COMPANY, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-1125168
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001702494
Appalachian Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3457
Entity Registrant Name	APPALACHIAN POWER COMPANY
Entity Incorporation, State or Country Code	VA
Entity Tax Identification Number	54-0124790
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		13,499,500
Entity Central Index Key	0000006879
Indiana Michigan Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3570
Entity Registrant Name	INDIANA MICHIGAN POWER COMPANY
Entity Incorporation, State or Country Code	IN
Entity Tax Identification Number	35-0410455
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		1,400,000
Entity Central Index Key	0000050172
Ohio Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-6543
Entity Registrant Name	OHIO POWER COMPANY
Entity Incorporation, State or Country Code	OH
Entity Tax Identification Number	31-4271000
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		27,952,473
Entity Central Index Key	0000073986
Public Service Co Of Oklahoma [Member]
Entity Information [Line Items]
Entity File Number	0-343
Entity Registrant Name	PUBLIC SERVICE COMPANY OF OKLAHOMA
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-0410895
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		9,013,000
Entity Central Index Key	0000081027
Southwestern Electric Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3146
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER COMPANY
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	72-0323455
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		7,536,640
Entity Central Index Key	0000092487
New York Stock Exchange | Common Stock [Member]
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $6.50 par value
Trading Symbol	AEP
Security Exchange Name	NYSE
New York Stock Exchange | Preferred Stock [Member]
Entity Information [Line Items]
Title of 12(b) Security	6.125% Corporate Units
Trading Symbol	AEP PR B
Security Exchange Name	NYSE

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2019		Sep. 30, 2018		Sep. 30, 2019		Sep. 30, 2018
Revenues
Revenue from Contracts with Customers	$ 4,315		$ 4,333.1		$ 11,945.4		$ 12,394.6
Sales to AEP Affiliates	0		0		0		0
TOTAL REVENUES	4,315		4,333.1		11,945.4		12,394.6
Expenses
Other Operation	708.3		826		1,981.7		2,332.7
Maintenance	267.7		316.6		890.9		911
Depreciation and Amortization	645.2		602.6		1,873.6		1,695.5
Taxes Other Than Income Taxes	320.5		294.2		932.7		863
TOTAL EXPENSES	3,356.8		3,664.5		9,647.8		10,263
OPERATING INCOME (LOSS)	958.2		668.6		2,297.6		2,131.6
Other Income (Expense):
Other Income	3.2		6.3		18.4		18.5
Allowance for Equity Funds Used During Construction	43		30.9		122.3		92.4
Non-Service Cost Components of Net Periodic Benefit Cost	30		31.9		90		95.3
Interest Expense	(275.1)		(256.8)		(781.6)		(733.1)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	759.3		480.9		1,746.7		1,604.7
Income Tax Expense (Benefit)	40.6		(80.7)		30.7		93.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries	15.2		18.1		51.1		55.3
Net Income (Loss)	733.9		579.7		1,767.1		1,566.5
Net Income (Loss) Attributable to Noncontrolling Interests	0.4		2.1		(0.5)		6.1
Earnings Attributable to Common Shareholders	$ 733.5		$ 577.6		$ 1,767.6		$ 1,560.4
Earnings Per Share
Weighted Average Number of Basic AEP Common Shares Outstanding	493,839,034		492,984,741		493,579,430		492,649,456
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$ 1.49		$ 1.17		$ 3.58		$ 3.17
Weighted Average Number of Diluted AEP Common Shares Outstanding	495,461,509		493,940,543		495,105,986		493,526,937
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	$ 1.48		$ 1.17		$ 3.57		$ 3.16
Common Stock, Dividends Per Share, Declared	$ 0.67		$ 0.62
Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	$ 2,598.9		$ 2,610.2		$ 7,087.6		$ 7,332.4
Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	1,147.3		1,180.9		3,328.7		3,450
Generation and Marketing [Member]
Revenues
Revenue from Contracts with Customers	501.2		486.5		1,323.8		1,399.3
Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	67.6		55.5		205.3		212.9
Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	274.2	[1]	240.8	[2]	838.4	[3]	944.7	[4]
Expenses
Cost of Goods and Services Sold	631.2		840.4		1,662.5		1,909.1
Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	783.9		784.7		2,306.4		2,551.7
AEP Texas Inc. [Member]
Revenues
Sales to AEP Affiliates	42.7		27.5		125.1		63.3
TOTAL REVENUES	489.3		433.4		1,318		1,193.3
Expenses
Other Operation	128.2		133.4		349.2		368.4
Maintenance	21.7		23.2		136.9		67.8
Depreciation and Amortization	170.2		133.3		464.8		364.9
Taxes Other Than Income Taxes	39.8		36.3		110.3		102.3
TOTAL EXPENSES	371.1		339.4		1,090.3		931.3
OPERATING INCOME (LOSS)	118.2		94		227.7		262
Other Income (Expense):
Interest Income	0.4		0.5		1.5		0
Allowance for Equity Funds Used During Construction	5.1		5.8		8.3		15.2
Non-Service Cost Components of Net Periodic Benefit Cost	2.8		3.1		8.4		9.2
Interest Expense	(35.8)		(37.3)		(92.7)		(108.9)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	90.7		66.1		153.2		177.5
Income Tax Expense (Benefit)	13.7		8.3		(38.8)		26.4
Net Income (Loss)	77		57.8		192		151.1
AEP Texas Inc. [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	445.4		404.5		1,190.3		1,127
AEP Texas Inc. [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	1.2		1.4		2.6		3
AEP Texas Inc. [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	0	[5]	0	[6]	0	[7]	0	[8]
Expenses
Cost of Goods and Services Sold	11.2		13.2		29.1		27.9
AEP Transmission Co [Member]
Revenues
Sales to AEP Affiliates	205.7		148.4		608		453.8
TOTAL REVENUES	259.7		194.4		770.1		586.2
Expenses
Other Operation	26		24.5		61.7		59.6
Maintenance	3.2		2.8		8.9		7.6
Depreciation and Amortization	45.3		34.9		128.4		97.5
Taxes Other Than Income Taxes	42.9		35.2		126.2		102.9
TOTAL EXPENSES	117.4		97.4		325.2		267.6
OPERATING INCOME (LOSS)	142.3		97		444.9		318.6
Other Income (Expense):
Interest Income	0.8		0.5		2.1		1.3
Allowance for Equity Funds Used During Construction	21		18		61.1		48.7
Interest Expense	(26.4)		(19.8)		(69.5)		(60.7)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	137.7		95.7		438.6		307.9
Income Tax Expense (Benefit)	30.1		17.6		90.7		63.7
Net Income (Loss)	107.6		78.1		347.9		244.2
AEP Transmission Co [Member] | Transmission [Member]
Revenues
Revenue from Contracts with Customers	54		46		162.1		132.3
AEP Transmission Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	0		0		0		0.1
AEP Transmission Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	0	[5]	0	[6]	0	[7]	0	[8]
Appalachian Power Co [Member]
Revenues
Sales to AEP Affiliates	56.6		42.9		154.6		138.7
TOTAL REVENUES	755.5		762		2,204.1		2,249.4
Expenses
Other Operation	140.4		131.9		416.2		380
Maintenance	61.5		97.2		184.3		234.9
Depreciation and Amortization	118.7		105.7		348.3		319.5
Taxes Other Than Income Taxes	36.7		33.6		108.5		101.1
TOTAL EXPENSES	612.9		712.2		1,832.5		1,874
OPERATING INCOME (LOSS)	142.6		49.8		371.6		375.4
Other Income (Expense):
Interest Income	0.3		0.4		2.1		1.3
Carrying Costs Income	0		0.2		0		1.2
Allowance for Equity Funds Used During Construction	4.8		4.1		12.5		9.6
Non-Service Cost Components of Net Periodic Benefit Cost	4.3		4.5		12.8		13.4
Interest Expense	(51.6)		(50.8)		(152.5)		(146)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	100.4		8.2		246.5		254.9
Income Tax Expense (Benefit)	(3.9)		(78.9)		(47)		(35.1)
Net Income (Loss)	104.3		87.1		293.5		290
Appalachian Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	696.7		716.8		2,041.3		2,103.1
Appalachian Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	2.2		2.3		8.2		7.6
Appalachian Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	70.4	[5]	74.5	[6]	200.1	[7]	194.1	[8]
Sales to AEP Affiliates	32		30		96		100
Expenses
Cost of Goods and Services Sold	177.3		263.4		521.8		487.7
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	78.3		80.4		253.4		350.8
Indiana Michigan Power Co [Member]
Revenues
Sales to AEP Affiliates	2.7		3.4		7.3		18.9
Other Revenues - Affiliated	16.2		13.7		50.4		43.3
TOTAL REVENUES	611.1		629.7		1,768.5		1,796.2
Expenses
Purchased Electricity from AEP Affiliates	61		60		172.1		181.8
Other Operation	172.7		149.3		467.7		425.8
Maintenance	50.9		57.2		163.8		169.1
Depreciation and Amortization	88.1		85.2		261.6		207.1
Taxes Other Than Income Taxes	25.1		23		78.6		72.9
TOTAL EXPENSES	503.8		519.5		1,468.3		1,471.2
OPERATING INCOME (LOSS)	107.3		110.2		300.2		325
Other Income (Expense):
Other Income	3.5		6.1		15.3		15.4
Allowance for Equity Funds Used During Construction					16.4		8
Non-Service Cost Components of Net Periodic Benefit Cost	4.5		4.6		13.3		13.6
Interest Expense	(28.8)		(34.5)		(85.9)		(95.6)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	86.5		86.4		242.9		258.4
Income Tax Expense (Benefit)	(2.3)		13.7		(5.1)		26.8
Net Income (Loss)	88.8		72.7		248		231.6
Indiana Michigan Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	589.1		609.9		1,703.2		1,723.9
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	3.1		2.7		7.6		10.1
Sales to AEP Affiliates	20		17		57		57
Indiana Michigan Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	102.1	[5]	93.6	[6]	327.4	[7]	349.7	[8]
Expenses
Cost of Goods and Services Sold	61.2		95.9		161.2		246.8
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	44.8		48.9		163.3		167.7
Ohio Power Co [Member]
Revenues
Sales to AEP Affiliates	9		3.3		18.2		17.9
TOTAL REVENUES	710.6		778.3		2,154		2,318
Expenses
Purchased Electricity from AEP Affiliates	40.6		39.3		120.4		97.4
Amortization of Generation Deferrals	8.8		56.9		65.3		171.9
Other Operation	194.9		215.2		565.7		586.4
Maintenance	40		43.4		106.7		114.7
Depreciation and Amortization	57.4		70.4		176.8		200.3
Taxes Other Than Income Taxes	112		106.9		326.9		311
TOTAL EXPENSES	612		698.4		1,815.8		2,016.4
OPERATING INCOME (LOSS)	98.6		79.9		338.2		301.6
Other Income (Expense):
Interest Income	0.8		0.8		2.7		2.6
Carrying Costs Income	0.3		0.2		0.7		1.5
Allowance for Equity Funds Used During Construction	4.8		2		14.1		7.8
Non-Service Cost Components of Net Periodic Benefit Cost	3.7		3.8		11		11.6
Interest Expense	(27.9)		(26.1)		(78.1)		(76.6)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	80.3		60.6		288.6		248.5
Income Tax Expense (Benefit)	11.2		(28.1)		40.9		11.4
Net Income (Loss)	69.1		88.7		247.7		237.1
Ohio Power Co [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	698.6		772.6		2,127.4		2,294.8
Ohio Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	3		2.4		8.4		5.3
Ohio Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	0	[5]	0	[6]	0	[7]	0	[8]
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	158.3		166.3		454		534.7
Public Service Co Of Oklahoma [Member]
Revenues
Sales to AEP Affiliates	1.3		1.1		5		3.7
TOTAL REVENUES	493		481.4		1,173.9		1,216.5
Expenses
Other Operation	87.6		106.3		226		286.8
Maintenance	21.5		22.3		70.1		73.2
Depreciation and Amortization	39.1		42.3		125.4		120.5
Taxes Other Than Income Taxes	11.1		10.8		33		32.6
TOTAL EXPENSES	373		402.9		976.4		1,076.9
OPERATING INCOME (LOSS)	120		78.5		197.5		139.6
Other Income (Expense):
Other Income	1.2		(0.2)		2.1		(0.3)
Allowance for Equity Funds Used During Construction					1.5		(0.3)
Non-Service Cost Components of Net Periodic Benefit Cost	2.1		2.1		6.3		6.5
Interest Expense	(16.1)		(16.4)		(50.3)		(47.4)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	107.2		64		155.6		98.4
Income Tax Expense (Benefit)	6.9		3.6		7.2		8.6
Net Income (Loss)	100.3		60.4		148.4		89.8
Public Service Co Of Oklahoma [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	490.5		479.1		1,164.3		1,209.5
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	1.2		1.2		4.6		3.3
Public Service Co Of Oklahoma [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	21.1	[5]	12.5	[6]	35.5	[7]	26.7	[8]
Expenses
Cost of Goods and Services Sold	98.4		104.4		181.2		211.5
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	115.3		116.8		340.7		352.3
Southwestern Electric Power Co [Member]
Revenues
Sales to AEP Affiliates	8.8		8.7		21.6		20.2
Provision for Refund	(0.1)		0		(25.3)		0
TOTAL REVENUES	545.5		535.3		1,342.1		1,411.8
Expenses
Other Operation	91.9		99.1		242.4		292
Maintenance	35.9		33.6		104.1		102.2
Depreciation and Amortization	63.2		59.9		187.1		175.9
Taxes Other Than Income Taxes	26.2		26.9		76		76.4
TOTAL EXPENSES	410.8		408.2		1,120.3		1,172.6
OPERATING INCOME (LOSS)	134.7		127.1		221.8		239.2
Other Income (Expense):
Interest Income	0.6		1.1		2		3.5
Allowance for Equity Funds Used During Construction	1.6		0.6		4.5		3.8
Non-Service Cost Components of Net Periodic Benefit Cost	2.1		2.3		6.4		6.9
Interest Expense	(29.2)		(32.7)		(89.4)		(95.8)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	109.8		98.4		145.3		157.6
Income Tax Expense (Benefit)	(0.7)		9.6		0		17.9
Equity Earnings (Loss) of Unconsolidated Subsidiaries	0.8		0.8		2.3		2
Net Income (Loss)	111.3		89.6		147.6		141.7
Net Income (Loss) Attributable to Noncontrolling Interests	0.8		1.4		3.1		4.1
Earnings Attributable to Common Shareholders	110.5		88.2		144.5		137.6
Southwestern Electric Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	536.5		526		1,344.8		1,390.4
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	0.3		0.6		1		1.2
Southwestern Electric Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	50.7	[5]	53.2	[6]	152.7	[7]	168.8	[8]
Expenses
Cost of Goods and Services Sold	148.8		152.1		400.2		393.4
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	$ 44.8		$ 36.6		$ 110.5		$ 132.7
[1]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million . The remaining affiliated amounts were immaterial.
[2]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million . The remaining affiliated amounts were immaterial.
[3]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million . The remaining affiliated amounts were immaterial.
[4]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $87 million
[5]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[6]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[7]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[8]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenue from Contracts with Customers		$ 4,315	$ 4,333.1	$ 11,945.4	$ 12,394.6
Net Income (Loss)		733.9	579.7	1,767.1	1,566.5
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		44.2	10.2	(63.3)	14.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax		(1.4)	(1.4)	(4.2)	(4)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		42.8	8.8	(67.5)	10.7
TOTAL COMPREHENSIVE INCOME (LOSS)		776.7	588.5	1,699.6	1,577.2
Total Comprehensive Income (Loss) Attributable to Noncontrolling Interest		0.4	2.1	(0.5)	6.1
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		776.3	586.4	1,700.1	1,571.1
Appalachian Power Co [Member]
Net Income (Loss)		104.3	87.1	293.5	290
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		(0.3)	(0.3)	(0.7)	(0.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax		(0.6)	(0.7)	(1.9)	(2.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.9)	(1)	(2.6)	(3)
TOTAL COMPREHENSIVE INCOME (LOSS)		103.4	86.1	290.9	287
AEP Texas Inc. [Member]
Net Income (Loss)		77	57.8	192	151.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.3	0.3	0.8	0.8
Amortization of Pension and OPEB Deferred Costs, Net of Tax		0	0	0.1	0.1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.3	0.3	0.9	0.9
TOTAL COMPREHENSIVE INCOME (LOSS)		77.3	58.1	192.9	152
Indiana Michigan Power Co [Member]
Net Income (Loss)		88.8	72.7	248	231.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.4	0.3	1.2	1.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax		0	0	(0.1)	0
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.4	0.3	1.1	1.2
TOTAL COMPREHENSIVE INCOME (LOSS)		89.2	73	249.1	232.8
Ohio Power Co [Member]
Net Income (Loss)		69.1	88.7	247.7	237.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		(0.3)	(0.4)	(1)	(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.3)	(0.4)
TOTAL COMPREHENSIVE INCOME (LOSS)		68.8	88.3	246.7	236.1
Public Service Co Of Oklahoma [Member]
Net Income (Loss)		100.3	60.4	148.4	89.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		(0.2)	(0.2)	(0.7)	(0.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.2)	(0.2)
TOTAL COMPREHENSIVE INCOME (LOSS)		100.1	60.2	147.7	89.1
Southwestern Electric Power Co [Member]
Net Income (Loss)		111.3	89.6	147.6	141.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.3	2.7	1.1	3.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax		(0.3)	(0.3)	(0.9)	(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0	2.4	0.2	2.6
TOTAL COMPREHENSIVE INCOME (LOSS)		111.3	92	147.8	144.3
Total Comprehensive Income (Loss) Attributable to Noncontrolling Interest		0.8	1.4	3.1	4.1
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		110.5	90.6	144.7	140.2
Generation and Marketing Revenues [Member]
Revenue from Contracts with Customers		501.2	486.5	1,323.8	1,399.3
Reclassification out of Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Revenue from Contracts with Customers	[1]	(0.1)	(0.1)	(0.1)	(0.1)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(1.4)	(1.4)	(4.2)	(4)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Appalachian Power Co [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.6)	(0.7)	(1.9)	(2.3)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | AEP Texas Inc. [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0	0	0.1	0.1
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Indiana Michigan Power Co [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0	0	(0.1)	0
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Southwestern Electric Power Co [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.3)	(0.3)	(0.9)	(1)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Revenue from Contracts with Customers	[1]	$ 0	$ 0	$ 0	$ 0
[1]	Amounts reclassified to the referenced line item on the statements of income.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Cash Flow Hedges, Tax	$ 11.8	$ 2.7	$ (16.8)	$ 3.9
Amortization of Pension and OPEB Deferred Costs, Tax	(0.4)	(0.4)	(1.1)	(1.1)
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.2)	(0.2)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.2)	(0.2)	(0.5)	(0.6)
AEP Texas Inc. [Member]
Cash Flow Hedges, Tax	0.1	0.1	0.2	0.2
Amortization of Pension and OPEB Deferred Costs, Tax	0	0	0	0
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.1	0.3	0.3
Amortization of Pension and OPEB Deferred Costs, Tax	0	0	0	0
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.3)	(0.3)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	0	0	(0.2)	(0.2)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.8	0.3	1
Amortization of Pension and OPEB Deferred Costs, Tax	$ 0	$ (0.1)	$ (0.2)	$ (0.3)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Appalachian Power Co [Member]	AEP Texas Inc. [Member]	AEP Transmission 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]Appalachian Power Co [Member]	Additional Paid-in Capital [Member]AEP Texas Inc. [Member]	Additional Paid-in Capital [Member]AEP Transmission 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]Appalachian Power Co [Member]	Retained Earnings [Member]AEP Texas Inc. [Member]	Retained Earnings [Member]AEP Transmission Co [Member]	Retained Earnings [Member]Indiana Michigan Power Co [Member]	Retained Earnings [Member]Ohio Power Co [Member]	Retained Earnings [Member]Public Service Co Of Oklahoma [Member]	Retained Earnings [Member]Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]	Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member]	Accumulated Other Comprehensive Income [Member]AEP Texas Inc. [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]	AEP Wind Holdings LLC [Member]	AEP Wind Holdings LLC [Member]Noncontrolling Interests [Member]	Santa Rita East [Member]	Santa Rita East [Member]Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2017				$ 2,589.9															$ 1,816.6									$ 773.3
Beginning Balance at Dec. 31, 2017	$ 18,313.6	$ 3,804.5	$ 2,169.9		$ 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		$ 1,828.7	$ 1,057.9		$ 980.9	$ 838.8	$ 364	$ 676.6	$ 8,626.7		$ 1,714.1	$ 1,124.6		$ 1,192.2	$ 1,148.4	$ 691.5	$ 1,426.6	$ (67.8)	$ 1.3	$ (12.6)	$ (12.1)	$ 1.9	$ 2.6	$ (4)	$ 26.6	$ (0.4)
Beginning Balance, Shares at Dec. 31, 2017									512,200,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	32.2								$ 3.3						28.9
Issuance of Common Stock, Shares									500,000
Common Stock Dividends	(306.1)																							(305.5)	[1]
Common Stock Dividends		(40)			(33.5)	(112.5)	(12.5)	(20)																		(40)			(33.5)	(112.5)	(12.5)	(20)
Common Stock Dividends								(0.8)																																(0.6)	(0.8)
Other Changes in Equity	16.9														16.9
Capital Contribution from Member			100	65														100	65
ASU 2018-02 Adoption	(3)	0.4	(0.9)		(2.4)	0.4	0.5	(1.3)																14		0.1	1.8		0.3			(0.4)	(17)	0.3	(2.7)	(2.7)	0.4	0.5	(0.9)
ASU 2016-01 Adoption	0																							11.9									(11.9)
Net Income (Loss)																								454.4								11.8
Net Income (Loss) Attributable to Noncontrolling Interests																																								2.3	1.6
Net Income (Loss)	456.7	125.5	46.8	84.1	64.2	79.6	(7.2)	13.4																		125.5	46.8	84.1	64.2	79.6	(7.2)
Other Comprehensive Income (Loss)	1.3	(1)	0.3		0.4	(0.3)	(0.2)	0.1																									1.3	(1)	0.3	0.4	(0.3)	(0.2)	0.1
Ending Balance at Mar. 31, 2018				2,739															1,881.6									857.4
Ending Balance at Mar. 31, 2018	$ 18,511.6	3,889.4	2,316.1		2,246.3	2,277.5	1,195.9	2,225.9	$ 3,332.7	260.4	56.6	321.2	157.2	135.7	6,444.5		1,828.7	1,157.9		980.9	838.8	364	676.6	8,801.5		1,799.7	1,173.2		1,223.2	1,115.5	671.8	1,418	(95.4)	0.6	(15)	(14.4)	2	2.9	(4.8)	28.3	0.4
Ending Balance, Shares at Mar. 31, 2018									512,700,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.62
Beginning Balance at Dec. 31, 2017				2,589.9															1,816.6									773.3
Beginning Balance at Dec. 31, 2017	$ 18,313.6	3,804.5	2,169.9		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		1,828.7	1,057.9		980.9	838.8	364	676.6	8,626.7		1,714.1	1,124.6		1,192.2	1,148.4	691.5	1,426.6	(67.8)	1.3	(12.6)	(12.1)	1.9	2.6	(4)	26.6	(0.4)
Beginning Balance, Shares at Dec. 31, 2017									512,200,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
ASU 2018-02 Adoption																																	(17)	0.3	(2.7)	(2.7)			(0.9)
ASU 2016-01 Adoption																																	(11.9)
Net Income (Loss)	1,560.4							137.6
Net Income (Loss) Attributable to Noncontrolling Interests	6.1							4.1
Net Income (Loss)	1,566.5	290	151.1	244.2	231.6	237.1	89.8	141.7
Other Comprehensive Income (Loss)	10.7	(3)	0.9		1.2			2.6
Ending Balance at Sep. 30, 2018				3,416.1															2,398.6									1,017.5
Ending Balance at Sep. 30, 2018	19,046.8	3,971.9	2,421		2,342.5	2,209.3	1,267.4	2,314.3	$ 3,336.5	260.4	56.6	321.2	157.2	135.7	6,472.6		1,828.7	1,157.9		980.9	838.8	364	676.6	9,293.7		1,884.2	1,277.5		1,318.6	1,048	743.8	1,503.8	(86)	(1.4)	(14.4)	(13.6)	1.3	2.4	(2.3)	30	0.5
Ending Balance, Shares at Sep. 30, 2018									513,300,000
Beginning Balance at Mar. 31, 2018				2,739															1,881.6									857.4
Beginning Balance at Mar. 31, 2018	18,511.6	3,889.4	2,316.1		2,246.3	2,277.5	1,195.9	2,225.9	$ 3,332.7	260.4	56.6	321.2	157.2	135.7	6,444.5		1,828.7	1,157.9		980.9	838.8	364	676.6	8,801.5		1,799.7	1,173.2		1,223.2	1,115.5	671.8	1,418	(95.4)	0.6	(15)	(14.4)	2	2.9	(4.8)	28.3	0.4
Beginning Balance, Shares at Mar. 31, 2018									512,700,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	18.7								$ 2.7						16
Issuance of Common Stock, Shares									400,000
Common Stock Dividends	(308.1)																							(306.8)	[1]
Common Stock Dividends		(40)			(33.5)	(112.5)	(12.5)	(20)																		(40)			(33.5)	(112.5)	(12.5)	(20)
Common Stock Dividends								(1)																																(1.3)	(1)
Other Changes in Equity	(1.5)														(1.9)																									0.4
Capital Contribution from Member				312															312
Net Income (Loss)																								528.4								37.6
Net Income (Loss) Attributable to Noncontrolling Interests																																								1.7	1.1
Net Income (Loss)	530.1	77.4	46.5	82	94.7	68.8	36.6	38.7																		77.4	46.5	82	94.7	68.8	36.6
Other Comprehensive Income (Loss)	0.6	(1)	0.3		0.5	(0.3)	(0.3)	0.1																									0.6	(1)	0.3	0.5	(0.3)	(0.3)	0.1
Ending Balance at Jun. 30, 2018				3,133															2,193.6									939.4
Ending Balance at Jun. 30, 2018	$ 18,751.4	3,925.8	2,362.9		2,308	2,233.5	1,219.7	2,243.7	$ 3,335.4	260.4	56.6	321.2	157.2	135.7	6,458.6		1,828.7	1,157.9		980.9	838.8	364	676.6	9,023.1		1,837.1	1,219.7		1,284.4	1,071.8	695.9	1,435.6	(94.8)	(0.4)	(14.7)	(13.9)	1.7	2.6	(4.7)	29.1	0.5
Ending Balance, Shares at Jun. 30, 2018									513,100,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.62
Issuance of Common Stock, Value	$ 11.6								$ 1.1						10.5
Issuance of Common Stock, Shares									200,000
Common Stock Dividends	(308.3)																							(307)	[1]
Common Stock Dividends		(40)			(38.5)	(112.5)	(12.5)	(20)																		(40)			(38.5)	(112.5)	(12.5)	(20)
Common Stock Dividends								(1.4)																																(1.3)	(1.4)
Other Changes in Equity	3.6														3.5																									0.1
Capital Contribution from Member				205															205
Net Income (Loss)	577.6							88.2																577.6								88.2
Net Income (Loss) Attributable to Noncontrolling Interests	2.1							1.4																																2.1	1.4
Net Income (Loss)	579.7	87.1	57.8	78.1	72.7	88.7	60.4	89.6																		87.1	57.8	78.1	72.7	88.7	60.4
Other Comprehensive Income (Loss)	8.8	(1)	0.3		0.3	(0.4)	(0.2)	2.4																									8.8	(1)	0.3	0.3	(0.4)	(0.2)	2.4
Ending Balance at Sep. 30, 2018				3,416.1															2,398.6									1,017.5
Ending Balance at Sep. 30, 2018	$ 19,046.8	3,971.9	2,421		2,342.5	2,209.3	1,267.4	2,314.3	$ 3,336.5	260.4	56.6	321.2	157.2	135.7	6,472.6		1,828.7	1,157.9		980.9	838.8	364	676.6	9,293.7		1,884.2	1,277.5		1,318.6	1,048	743.8	1,503.8	(86)	(1.4)	(14.4)	(13.6)	1.3	2.4	(2.3)	30	0.5
Ending Balance, Shares at Sep. 30, 2018									513,300,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.62
Beginning Balance at Dec. 31, 2018				3,569.8															2,480.6									1,089.2
Beginning Balance at Dec. 31, 2018	$ 19,059.4	4,006.1	2,580.5		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		1,828.7	1,257.9		980.9	838.8	364	676.6	9,325.3		1,922	1,337.7		1,329.1	1,136.4	724.7	1,508.4	(120.4)	(5)	(15.1)	(13.8)	1	2.1	(5.4)	31	0.3
Beginning Balance, Shares at Dec. 31, 2018	513,450,036						10,482,000		513,500,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	$ 14.5								$ 1.2						13.3
Issuance of Common Stock, Shares									100,000
Common Stock Dividends	(333.6)																							(332.5)	[2]
Common Stock Dividends		(50)			(20)	(25)	$ (11.3)	(18.7)																		(50)			(20)	(25)	(11.3)	(18.7)
Common Stock Dividends								(1.1)																																(1.1)	(1.1)
Other Changes in Equity	(55.6)														(56.6)	[3]																								1
Capital Contribution from Member			200															200
Net Income (Loss)																								572.8								27.8
Net Income (Loss) Attributable to Noncontrolling Interests																																								1.3	1.2
Net Income (Loss)	574.1	133.7	34.4	104.3	98.9	128	6.2	29																		133.7	34.4	104.3	98.9	128	6.2
Other Comprehensive Income (Loss)	(30.3)	(0.8)	0.3		0.4	(0.3)	(0.2)	0.1																									(30.3)	(0.8)	0.3	0.4	(0.3)	(0.2)	0.1
Ending Balance at Mar. 31, 2019				3,674.1															2,480.6									1,193.5
Ending Balance at Mar. 31, 2019	$ 19,228.5	4,089	2,815.2		2,432.1	2,400.1	1,242.7	2,324.9	$ 3,338.6	260.4	56.6	321.2	157.2	135.7	6,442.8		1,828.7	1,457.9		980.9	838.8	364	676.6	9,565.6		2,005.7	1,372.1		1,408	1,239.4	719.6	1,517.5	(150.7)	(5.8)	(14.8)	(13.4)	0.7	1.9	(5.3)	32.2	0.4
Ending Balance, Shares at Mar. 31, 2019									513,600,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.67
Beginning Balance at Dec. 31, 2018				3,569.8															2,480.6									1,089.2
Beginning Balance at Dec. 31, 2018	$ 19,059.4	4,006.1	2,580.5		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		1,828.7	1,257.9		980.9	838.8	364	676.6	9,325.3		1,922	1,337.7		1,329.1	1,136.4	724.7	1,508.4	(120.4)	(5)	(15.1)	(13.8)	1	2.1	(5.4)	31	0.3
Beginning Balance, Shares at Dec. 31, 2018	513,450,036						10,482,000		513,500,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other Changes in Equity																								(62)
Net Income (Loss)	$ 1,767.6							144.5
Net Income (Loss) Attributable to Noncontrolling Interests	(0.5)							3.1
Net Income (Loss)	1,767.1	293.5	192	347.9	248	247.7	$ 148.4	147.6
Other Comprehensive Income (Loss)	(67.5)	(2.6)	0.9		1.1			0.2
Ending Balance at Sep. 30, 2019				3,917.7															2,480.6									1,437.1
Ending Balance at Sep. 30, 2019	$ 19,997.7	4,172	2,973.4		2,541.9	2,459.1	$ 1,384.4	2,422.6	$ 3,341.9	260.4	56.6	321.2	157.2	135.7	6,467.1		1,828.7	1,457.9		980.9	838.8	364	676.6	10,095.3		2,090.5	1,529.7		1,517.1	1,299.1	861.8	1,615.4	(187.9)	(7.6)	(14.2)	(12.7)	0	1.4	(5.2)	281.3	0.1
Ending Balance, Shares at Sep. 30, 2019	514,140,235						10,482,000		514,100,000
Beginning Balance at Mar. 31, 2019				3,674.1															2,480.6									1,193.5
Beginning Balance at Mar. 31, 2019	$ 19,228.5	4,089	2,815.2		2,432.1	2,400.1	$ 1,242.7	2,324.9	$ 3,338.6	260.4	56.6	321.2	157.2	135.7	6,442.8		1,828.7	1,457.9		980.9	838.8	364	676.6	9,565.6		2,005.7	1,372.1		1,408	1,239.4	719.6	1,517.5	(150.7)	(5.8)	(14.8)	(13.4)	0.7	1.9	(5.3)	32.2	0.4
Beginning Balance, Shares at Mar. 31, 2019									513,600,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	17.8								$ 2.2						15.6
Issuance of Common Stock, Shares									400,000
Common Stock Dividends	(334.5)																							(332.7)	[2]
Common Stock Dividends		(50)			(20)	(60)		(18.8)																		(50)			(20)	(60)		(18.8)
Common Stock Dividends								(1.1)																																(1.8)	(1.1)
Other Changes in Equity	2.5														3.1																									(0.6)
Acquisition																																										$ 134.8	$ 134.8
Net Income (Loss)																								461.3								6.2
Net Income (Loss) Attributable to Noncontrolling Interests																																								(2.2)	1.1
Net Income (Loss)	459.1	55.5	80.6	136	60.3	50.6	41.9	7.3																		55.5	80.6	136	60.3	50.6	41.9
Other Comprehensive Income (Loss)	(80)	(0.9)	0.3		0.3	(0.4)	(0.3)	0.1																									(80)	(0.9)	0.3	0.3	(0.4)	(0.3)	0.1
Ending Balance at Jun. 30, 2019				3,810.1															2,480.6									1,329.5
Ending Balance at Jun. 30, 2019	$ 19,423.2	4,093.6	2,896.1		2,472.7	2,390.3	1,284.3	2,312.4	$ 3,340.8	260.4	56.6	321.2	157.2	135.7	6,455.3		1,828.7	1,457.9		980.9	838.8	364	676.6	9,694.2		2,011.2	1,452.7		1,448.3	1,230	761.5	1,504.9	(230.7)	(6.7)	(14.5)	(13.1)	0.3	1.6	(5.2)	163.6	0.4
Ending Balance, Shares at Jun. 30, 2019									514,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.67
Issuance of Common Stock, Value	$ 12.4								$ 1.1						11.3
Issuance of Common Stock, Shares									100,000
Common Stock Dividends	(333.9)																							(332.4)	[2]
Common Stock Dividends		(25)			(20)																					(25)			(20)
Common Stock Dividends								(1.1)																																(1.5)	(1.1)
Other Changes in Equity	0.5														0.5
Acquisition																																												$ 118.8	$ 118.8
Net Income (Loss)	733.5							110.5																733.5								110.5
Net Income (Loss) Attributable to Noncontrolling Interests	0.4							0.8																																0.4	0.8
Net Income (Loss)	733.9	104.3	77	107.6	88.8	69.1	100.3	111.3																		104.3	77	107.6	88.8	69.1	100.3
Other Comprehensive Income (Loss)	42.8	(0.9)	0.3		0.4	(0.3)	(0.2)	0																									42.8	(0.9)	0.3	0.4	(0.3)	(0.2)
Ending Balance at Sep. 30, 2019				$ 3,917.7															$ 2,480.6									$ 1,437.1
Ending Balance at Sep. 30, 2019	$ 19,997.7	$ 4,172	$ 2,973.4		$ 2,541.9	$ 2,459.1	$ 1,384.4	$ 2,422.6	$ 3,341.9	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,467.1		$ 1,828.7	$ 1,457.9		$ 980.9	$ 838.8	$ 364	$ 676.6	$ 10,095.3		$ 2,090.5	$ 1,529.7		$ 1,517.1	$ 1,299.1	$ 861.8	$ 1,615.4	$ (187.9)	$ (7.6)	$ (14.2)	$ (12.7)	$ 0	$ 1.4	$ (5.2)	$ 281.3	$ 0.1
Ending Balance, Shares at Sep. 30, 2019	514,140,235						10,482,000		514,100,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.67
[1]	Common Stock dividends declared per AEP common share were $0.62.
[2]	Common Stock dividends declared per AEP common share were $0.67.
[3]	Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 13 for additional information.

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents		$ 348.8	$ 234.1
Restricted Cash		141	210
Other Temporary Investments		198.4	159.1
Accounts Receivable:
Customers		609	699
Accrued Unbilled Revenues		268.8	209.3
Pledged Accounts Receivable - AEP Credit		955.6	999.8
Miscellaneous		36.6	55.2
Allowance for Uncollectible Accounts		(44.9)	(36.8)
Total Accounts Receivable		1,825.1	1,926.5
Fuel		437.8	341.5
Materials and Supplies		613.5	579.6
Risk Management Assets		186.7	162.8
Regulatory Asset for Under-Recovered Fuel Costs		98.5	150.1
Margin Deposits		54.2	141.4
Prepayments and Other Current Assets		262.4	208.8
TOTAL CURRENT ASSETS		4,166.4	4,113.9
Property, Plant and Equipment
Generation		22,624.4	21,699.9
Transmission		23,082.8	21,531
Distribution		21,991	21,195.4
Other Property, Plant and Equipment		4,510.2	4,265
Construction Work in Progress		5,244.5	4,393.9
Total Property, Plant and Equipment		77,452.9	73,085.2
Accumulated Depreciation and Amortization		18,760.2	17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		58,692.7	55,099.1
Other Noncurrent Assets
Regulatory Assets		3,131.4	3,310.4
Securitized Assets		938.7	920.6
Spent Nuclear Fuel and Decommissioning Trusts		2,835.2	2,474.9
Goodwill		52.5	52.5
Long-term Risk Management Assets		299	254
Operating Lease Assets		990	0
Deferred Charges and Other Noncurrent Assets		2,794.8	2,577.4
TOTAL OTHER NONCURRENT ASSETS		11,041.6	9,589.8
TOTAL ASSETS		73,900.7	68,802.8
Current Liabilities
Accounts Payable		1,766.8	1,874.3
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	750	750
Other Short-term Debt		1,760	1,160
Total Short-term Debt		2,510	1,910
Long-term Debt Due Within One Year		1,327.7	1,698.5
Risk Management Liabilities		75.3	55
Customer Deposits		381.4	412.2
Accrued Taxes		883.4	1,218
Accrued Interest		304.8	231.7
Obligations Under Operating Leases		228.8	0
Regulatory Liability for Over-Recovered Fuel Costs		100.6	58.6
Other Current Liabilities		1,032.4	1,190.5
TOTAL CURRENT LIABILITIES		8,611.2	8,648.8
Noncurrent Liabilities
Long-term Debt		24,553.5	21,648.2
Long-term Risk Management Liabilities		298.6	263.4
Deferred Income Taxes		7,427.8	7,086.5
Regulatory Liabilities and Deferred Investment Tax Credits		8,552.8	8,540.3
Asset Retirement Obligations		2,353.5	2,287.7
Employee Benefits and Pension Obligations		376.6	377.1
Obligations Under Operating Leases		801.1	0
Deferred Credits and Other Noncurrent Liabilities		790	782.6
TOTAL NONCURRENT LIABILITIES		45,153.9	40,985.8
TOTAL LIABILITIES		53,765.1	49,634.6
Rate Matters
Commitments and Contingencies
Redeemable Noncontrolling Interest		67.3	69.4
Contingently Reedemable Performance Share Awards		70.6	39.4
Total Mezzanine Equity		137.9	108.8
Equity
Common Stock		3,341.9	3,337.4
Paid-in Capital		6,467.1	6,486.1
Retained Earnings		10,095.3	9,325.3
Accumulated Other Comprehensive Income (Loss)		(187.9)	(120.4)
TOTAL COMMON SHAREHOLDER'S EQUITY		19,716.4	19,028.4
Noncontrolling Interests		281.3	31
TOTAL EQUITY		19,997.7	19,059.4
TOTAL LIABILITIES AND EQUITY		73,900.7	68,802.8
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents		0.1	3.1
Restricted Cash		114.3	156.7
Advances to Affiliates		7.7	8
Accounts Receivable:
Customers		148	110.9
Affiliated Companies		17.6	15
Accrued Unbilled Revenues		82.7	70.4
Miscellaneous		0.2	1.9
Allowance for Uncollectible Accounts		(1.6)	(1.3)
Total Accounts Receivable		246.9	196.9
Fuel		7.1	8.8
Materials and Supplies		54.6	52.8
Accrued Tax Benefits		111.3	44.9
Prepayments and Other Current Assets		6.4	5.3
TOTAL CURRENT ASSETS		548.4	476.5
Property, Plant and Equipment
Generation		351.8	352.1
Transmission		4,102.8	3,683.6
Distribution		4,122.2	4,043.2
Other Property, Plant and Equipment		775.3	727.9
Construction Work in Progress		978.4	836.2
Total Property, Plant and Equipment		10,330.5	9,643
Accumulated Depreciation and Amortization		1,742.7	1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,587.8	7,991.8
Other Noncurrent Assets
Regulatory Assets		259.6	430
Securitized Assets		698.1	649.1
Deferred Charges and Other Noncurrent Assets		161.9	56.3
TOTAL OTHER NONCURRENT ASSETS		1,119.6	1,135.4
TOTAL ASSETS		10,255.8	9,603.7
Current Liabilities
Advances from Affiliates		74.8	216
Accounts Payable		224.1	276.5
Affiliated Companies		41	30.3
Short-term Debt:
Long-term Debt Due Within One Year		391.4	501.1
Risk Management Liabilities		0.3	0.2
Accrued Taxes		108.5	75.5
Accrued Interest		50.6	37.3
Oklaunion Purchase Power Agreement - Current		28.7	24.3
Obligations Under Operating Leases		11.7	0
Other Current Liabilities		85.1	98.3
TOTAL CURRENT LIABILITIES		1,016.2	1,259.5
Noncurrent Liabilities
Long-term Debt		3,755.1	3,380.2
Long-term Risk Management Liabilities		0.1	0
Deferred Income Taxes		977.7	913.1
Regulatory Liabilities and Deferred Investment Tax Credits		1,325.1	1,344.3
Oklaunion Purchase Power Agreement		0	22.1
Obligations Under Operating Leases		71.1	0
Deferred Credits and Other Noncurrent Liabilities		137.1	104
TOTAL NONCURRENT LIABILITIES		6,266.2	5,763.7
TOTAL LIABILITIES		7,282.4	7,023.2
Rate Matters
Commitments and Contingencies
Equity
Paid-in Capital		1,457.9	1,257.9
Retained Earnings		1,529.7	1,337.7
Accumulated Other Comprehensive Income (Loss)		(14.2)	(15.1)
TOTAL EQUITY		2,973.4	2,580.5
TOTAL LIABILITIES AND EQUITY		10,255.8	9,603.7
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0	0
Advances to Affiliates		275.2	96.9
Accounts Receivable:
Customers		23.5	11.8
Affiliated Companies		61.3	61
Total Accounts Receivable		84.8	72.8
Materials and Supplies		15.1	19
Accrued Tax Benefits		9.7	33.4
Prepayments and Other Current Assets		4.4	3.4
TOTAL CURRENT ASSETS		389.2	225.5
Property, Plant and Equipment
Transmission		7,181.8	6,515.8
Other Property, Plant and Equipment		227.2	174
Construction Work in Progress		1,858.4	1,578.3
Total Property, Plant and Equipment		9,267.4	8,268.1
Accumulated Depreciation and Amortization		368.8	271.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,898.6	7,996.2
Other Noncurrent Assets
Accounts Receivable - Affiliated Companies		4.8	0
Regulatory Assets		7.3	12.9
Deferred Property Taxes		47.2	157.9
Deferred Charges and Other Noncurrent Assets		5.6	1.6
TOTAL OTHER NONCURRENT ASSETS		64.9	172.4
TOTAL ASSETS		9,352.7	8,394.1
Current Liabilities
Advances from Affiliates		9.1	45.4
Accounts Payable		319.1	347.2
Affiliated Companies		57.1	56
Short-term Debt:
Long-term Debt Due Within One Year		85	85
Accrued Taxes		172.4	288.9
Accrued Interest		39.7	15.9
Obligations Under Operating Leases		2.3	0
Other Current Liabilities		25.5	3.8
TOTAL CURRENT LIABILITIES		710.2	842.2
Noncurrent Liabilities
Long-term Debt		3,426.9	2,738
Deferred Income Taxes		751.4	704.4
Regulatory Liabilities and Deferred Investment Tax Credits		541.2	521.3
Obligations Under Operating Leases		2.2	0
Deferred Credits and Other Noncurrent Liabilities		3.1	18.4
TOTAL NONCURRENT LIABILITIES		4,724.8	3,982.1
TOTAL LIABILITIES		5,435	4,824.3
Rate Matters
Commitments and Contingencies
Equity
Paid-in Captial		2,480.6	2,480.6
Retained Earnings		1,437.1	1,089.2
TOTAL MEMBER'S EQUITY		3,917.7	3,569.8
TOTAL LIABILITIES AND EQUITY		9,352.7	8,394.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.5	4.2
Restricted Cash		17.1	25.6
Advances to Affiliates		22.7	23
Accounts Receivable:
Customers		112.1	146.5
Affiliated Companies		56.4	73.4
Accrued Unbilled Revenues		56.9	63.5
Miscellaneous		1	2.3
Allowance for Uncollectible Accounts		(2.3)	(2.3)
Total Accounts Receivable		224.1	283.4
Fuel		108.8	61.3
Materials and Supplies		102.1	100.1
Risk Management Assets		56.5	57.2
Regulatory Asset for Under-Recovered Fuel Costs		43.7	99.6
Prepayments and Other Current Assets		36.3	44.3
TOTAL CURRENT ASSETS		614.8	698.7
Property, Plant and Equipment
Generation		6,560.5	6,509.6
Transmission		3,412.4	3,317.7
Distribution		4,126.7	3,989.4
Other Property, Plant and Equipment		525.3	485.8
Construction Work in Progress		667.4	490.2
Total Property, Plant and Equipment		15,292.3	14,792.7
Accumulated Depreciation and Amortization		4,300.2	4,124.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,992.1	10,668.3
Other Noncurrent Assets
Regulatory Assets		474.2	475.8
Securitized Assets		240.6	258.7
Long-term Risk Management Assets		0.2	0.9
Operating Lease Assets		79.4	0
Deferred Charges and Other Noncurrent Assets		159.3	188.1
TOTAL OTHER NONCURRENT ASSETS		953.7	923.5
TOTAL ASSETS		12,560.6	12,290.5
Current Liabilities
Advances from Affiliates		40.4	205.6
Accounts Payable		298.5	263.8
Affiliated Companies		90.8	84
Short-term Debt:
Long-term Debt Due Within One Year		215.6	430.7
Risk Management Liabilities		1.1	0.4
Customer Deposits		85.1	88.4
Accrued Taxes		58.2	89.3
Accrued Interest		67.5	41.5
Obligations Under Operating Leases		15.3	0
Other Current Liabilities		107.6	150.3
TOTAL CURRENT LIABILITIES		980.1	1,354
Noncurrent Liabilities
Long-term Debt		4,147.3	3,631.9
Long-term Risk Management Liabilities		0.3	0.2
Deferred Income Taxes		1,640.8	1,625.8
Regulatory Liabilities and Deferred Investment Tax Credits		1,336.9	1,449.7
Asset Retirement Obligations		108.2	107.1
Employee Benefits and Pension Obligations		52.7	57.1
Obligations Under Operating Leases		64.8	0
Deferred Credits and Other Noncurrent Liabilities		57.5	58.6
TOTAL NONCURRENT LIABILITIES		7,408.5	6,930.4
TOTAL LIABILITIES		8,388.6	8,284.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		260.4	260.4
Paid-in Capital		1,828.7	1,828.7
Retained Earnings		2,090.5	1,922
Accumulated Other Comprehensive Income (Loss)		(7.6)	(5)
TOTAL EQUITY		4,172	4,006.1
TOTAL LIABILITIES AND EQUITY		12,560.6	12,290.5
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.5	2.4
Advances to Affiliates		13.2	12.7
Accounts Receivable:
Customers		45	63.1
Affiliated Companies		45.3	75
Accrued Unbilled Revenues		2.7	3.6
Miscellaneous		1	1.4
Allowance for Uncollectible Accounts		(0.1)	(0.1)
Total Accounts Receivable		93.9	143
Fuel		39.8	37.3
Materials and Supplies		169.9	167.3
Risk Management Assets		10.5	8.6
Accrued Tax Benefits		43.2	26.6
Accrued Reimbursement of Spent Nuclear Fuel Costs		24.2	7.9
Prepayments and Other Current Assets		16.9	24.6
TOTAL CURRENT ASSETS		414.1	430.4
Property, Plant and Equipment
Generation		5,002	4,887.2
Transmission		1,614.5	1,576.8
Distribution		2,373.3	2,249.7
Other Property, Plant and Equipment		607.2	583.8
Construction Work in Progress		516.2	465.3
Total Property, Plant and Equipment		10,113.2	9,762.8
Accumulated Depreciation and Amortization		3,280.5	3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,832.7	6,611.2
Other Noncurrent Assets
Regulatory Assets		490.2	512.5
Spent Nuclear Fuel and Decommissioning Trusts		2,835.2	2,474.9
Long-term Risk Management Assets		0.1	0.6
Operating Lease Assets		295.3	0
Deferred Charges and Other Noncurrent Assets		129.6	193
TOTAL OTHER NONCURRENT ASSETS		3,750.4	3,181
TOTAL ASSETS		10,997.2	10,222.6
Current Liabilities
Advances from Affiliates		102.4	1.1
Accounts Payable		148.4	174.7
Affiliated Companies		71.6	70.2
Short-term Debt:
Long-term Debt Due Within One Year		147.4	155.4
Risk Management Liabilities		0.2	0.3
Customer Deposits		37.9	38
Accrued Taxes		57.9	90.7
Accrued Interest		20.5	37.3
Obligations Under Operating Leases		82	0
Regulatory Liability for Over-Recovered Fuel Costs		7.3	27.4
Other Current Liabilities		85.5	103
TOTAL CURRENT LIABILITIES		761.1	698.1
Noncurrent Liabilities
Long-term Debt		2,884.1	2,880
Long-term Risk Management Liabilities		0	0.1
Deferred Income Taxes		970	948
Regulatory Liabilities and Deferred Investment Tax Credits		1,809	1,574.5
Asset Retirement Obligations		1,731.5	1,681.3
Obligations Under Operating Leases		234	0
Deferred Credits and Other Noncurrent Liabilities		65.6	87.8
TOTAL NONCURRENT LIABILITIES		7,694.2	7,171.7
TOTAL LIABILITIES		8,455.3	7,869.8
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,517.1	1,329.1
Accumulated Other Comprehensive Income (Loss)		(12.7)	(13.8)
TOTAL EQUITY		2,541.9	2,352.8
TOTAL LIABILITIES AND EQUITY		10,997.2	10,222.6
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		4.7	4.9
Restricted Cash		0	27.6
Accounts Receivable:
Customers		35.4	111.1
Affiliated Companies		56.2	70.8
Accrued Unbilled Revenues		26.5	21.4
Miscellaneous		0.3	0.3
Allowance for Uncollectible Accounts		(2.1)	(1)
Total Accounts Receivable		116.3	202.6
Materials and Supplies		48.5	42.9
Renewable Energy Credits		41.5	25.9
Prepayments and Other Current Assets		19.8	15.7
TOTAL CURRENT ASSETS		230.8	319.6
Property, Plant and Equipment
Transmission		2,613	2,544.3
Distribution		5,192.8	4,942.3
Other Property, Plant and Equipment		662.3	574.8
Construction Work in Progress		485.3	432.1
Total Property, Plant and Equipment		8,953.4	8,493.5
Accumulated Depreciation and Amortization		2,256.1	2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,697.3	6,274.9
Other Noncurrent Assets
Regulatory Assets		372.2	387.5
Securitized Assets		0	12.9
Deferred Charges and Other Noncurrent Assets		320.3	441
TOTAL OTHER NONCURRENT ASSETS		692.5	841.4
TOTAL ASSETS		7,620.6	7,435.9
Current Liabilities
Advances from Affiliates		17.6	114.1
Accounts Payable		203.1	211.9
Affiliated Companies		100.2	102.9
Short-term Debt:
Long-term Debt Due Within One Year		0.1	47.9
Risk Management Liabilities		7.2	5.8
Customer Deposits		88.2	113.1
Accrued Taxes		294.3	537.8
Accrued Interest		44.7	31.4
Obligations Under Operating Leases		12.8	0
Other Current Liabilities		99.4	182.8
TOTAL CURRENT LIABILITIES		867.6	1,347.7
Noncurrent Liabilities
Long-term Debt		2,113.8	1,668.7
Long-term Risk Management Liabilities		105.7	93.8
Deferred Income Taxes		805	763.3
Regulatory Liabilities and Deferred Investment Tax Credits		1,143.6	1,221.2
Obligations Under Operating Leases		75.9	0
Deferred Credits and Other Noncurrent Liabilities		49.9	43.8
TOTAL NONCURRENT LIABILITIES		4,293.9	3,790.8
TOTAL LIABILITIES		5,161.5	5,138.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		1,299.1	1,136.4
Accumulated Other Comprehensive Income (Loss)		0	1
TOTAL EQUITY		2,459.1	2,297.4
TOTAL LIABILITIES AND EQUITY		7,620.6	7,435.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		2.9	2
Advances to Affiliates		95.1	0
Accounts Receivable:
Customers		25.2	32.5
Affiliated Companies		27.3	26.2
Miscellaneous		4	5.7
Allowance for Uncollectible Accounts		(0.4)	(0.1)
Total Accounts Receivable		56.1	64.3
Fuel		12.8	12.3
Materials and Supplies		46.2	44.8
Risk Management Assets		21.7	10.4
Accrued Tax Benefits		17	14.7
Prepayments and Other Current Assets		11.5	9.4
TOTAL CURRENT ASSETS		263.3	157.9
Property, Plant and Equipment
Generation		1,569.9	1,577
Transmission		928.4	892.3
Distribution		2,650.1	2,572.8
Other Property, Plant and Equipment		319.6	303.5
Construction Work in Progress		128.8	94
Total Property, Plant and Equipment		5,596.8	5,439.6
Accumulated Depreciation and Amortization		1,558.5	1,472.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		4,038.3	3,966.7
Other Noncurrent Assets
Regulatory Assets		380.7	369
Employee Benefits and Pension Assets		32.6	31.7
Operating Lease Assets		37.1	0
Deferred Charges and Other Noncurrent Assets		17.2	7.1
TOTAL OTHER NONCURRENT ASSETS		467.6	407.8
TOTAL ASSETS		4,769.2	4,532.4
Current Liabilities
Advances from Affiliates		0	105.5
Accounts Payable		128.6	126.9
Affiliated Companies		38.6	47.1
Short-term Debt:
Long-term Debt Due Within One Year		138.2	375.5
Risk Management Liabilities		0.3	1
Customer Deposits		59	58.6
Accrued Taxes		43.7	22.4
Obligations Under Operating Leases		6	0
Regulatory Liability for Over-Recovered Fuel Costs		69.9	20.1
Other Current Liabilities		67.7	64.5
TOTAL CURRENT LIABILITIES		552	821.6
Noncurrent Liabilities
Long-term Debt		1,248.2	911.5
Deferred Income Taxes		617.5	607.8
Regulatory Liabilities and Deferred Investment Tax Credits		858.9	864.7
Asset Retirement Obligations		50.9	46.3
Obligations Under Operating Leases		31.2	0
Deferred Credits and Other Noncurrent Liabilities		26.1	32.5
TOTAL NONCURRENT LIABILITIES		2,832.8	2,462.8
TOTAL LIABILITIES		3,384.8	3,284.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		861.8	724.7
Accumulated Other Comprehensive Income (Loss)		1.4	2.1
TOTAL EQUITY		1,384.4	1,248
TOTAL LIABILITIES AND EQUITY		4,769.2	4,532.4
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		21.4	24.5
Advances to Affiliates		8.5	83.4
Accounts Receivable:
Customers		20.6	24.5
Affiliated Companies		56.8	28.8
Miscellaneous		16.6	20.2
Allowance for Uncollectible Accounts		(1.4)	(0.7)
Total Accounts Receivable		92.6	72.8
Fuel		135.9	120.5
Materials and Supplies		69.8	67.5
Risk Management Assets		9.4	4.8
Regulatory Asset for Under-Recovered Fuel Costs		11.1	18.8
Prepayments and Other Current Assets		24.4	22.2
TOTAL CURRENT ASSETS		373.1	414.5
Property, Plant and Equipment
Generation		4,676.1	4,672.6
Transmission		1,995.9	1,866.9
Distribution		2,241.1	2,178.6
Other Property, Plant and Equipment		703.2	762.7
Construction Work in Progress		235	199.3
Total Property, Plant and Equipment		9,851.3	9,680.1
Accumulated Depreciation and Amortization		2,848.2	2,808.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,003.1	6,871.8
Other Noncurrent Assets
Regulatory Assets		223.6	230.8
Deferred Charges and Other Noncurrent Assets		167.2	111.2
TOTAL OTHER NONCURRENT ASSETS		390.8	342
TOTAL ASSETS		7,767	7,628.3
Current Liabilities
Accounts Payable		127.6	129.1
Affiliated Companies		62.4	64.2
Short-term Debt:
Long-term Debt Due Within One Year		121.2	59.7
Risk Management Liabilities		1.7	0.4
Customer Deposits		65	64.5
Accrued Taxes		94.7	42.8
Accrued Interest		22.9	34.7
Obligations Under Operating Leases		5.9	0
Regulatory Liability for Over-Recovered Fuel Costs		17.4	11.1
Other Current Liabilities		108	106.4
TOTAL CURRENT LIABILITIES		626.8	512.9
Noncurrent Liabilities
Long-term Debt		2,535.7	2,653.7
Long-term Risk Management Liabilities		3	2.2
Deferred Income Taxes		919.1	902.8
Regulatory Liabilities and Deferred Investment Tax Credits		918.1	923
Asset Retirement Obligations		200.9	191.3
Obligations Under Operating Leases		32.5	0
Deferred Credits and Other Noncurrent Liabilities		108.3	126.8
TOTAL NONCURRENT LIABILITIES		4,717.6	4,799.8
TOTAL LIABILITIES		5,344.4	5,312.7
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,615.4	1,508.4
Accumulated Other Comprehensive Income (Loss)		(5.2)	(5.4)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,422.5	2,315.3
Noncontrolling Interests		0.1	0.3
TOTAL EQUITY		2,422.6	2,315.6
TOTAL LIABILITIES AND EQUITY		$ 7,767	$ 7,628.3
[1]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents	$ 348.8	$ 234.1
Restricted Cash	141	210
Other Temporary Investments	198.4	159.1
Fuel	437.8	341.5
Property, Plant and Equipment
Other Property, Plant and Equipment	4,510.2	4,265
Accumulated Depreciation and Amortization	18,760.2	17,986.1
Other Noncurrent Assets
Securitized Transition Assets	938.7	920.6
Current Liabilities
Long-term Debt Due Within One Year	1,327.7	1,698.5
Accrued Interest	304.8	231.7
Noncurrent Liabilities
Long-term Debt	$ 24,553.5	$ 21,648.2
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	514,140,235	513,450,036
Treasury Stock, Shares	20,204,160	20,204,160
AEP Subsidiaries [Member]
Current Assets
Restricted Cash	$ 141	$ 210
Other Temporary Investments	193.4	152.7
Current Liabilities
Long-term Debt Due Within One Year	544.7	406.5
Noncurrent Liabilities
Long-term Debt	918.4	1,109.2
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents	0.1	3.1
Restricted Cash	114.3	156.7
Fuel	7.1	8.8
Property, Plant and Equipment
Other Property, Plant and Equipment	775.3	727.9
Accumulated Depreciation and Amortization	1,742.7	1,651.2
Other Noncurrent Assets
Securitized Transition Assets	698.1	649.1
Current Liabilities
Long-term Debt Due Within One Year	391.4	501.1
Accrued Interest	50.6	37.3
Noncurrent Liabilities
Long-term Debt	3,755.1	3,380.2
AEP Texas Inc. [Member] | AEP Texas Transition Funding and Restoration Funding [Member]
Other Noncurrent Assets
Securitized Transition Assets	693	636.8
Current Liabilities
Long-term Debt Due Within One Year	280.8	251.1
Accrued Interest	6.1	11.3
Noncurrent Liabilities
Long-term Debt	530.5	540.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	3.5	4.2
Restricted Cash	17.1	25.6
Fuel	108.8	61.3
Property, Plant and Equipment
Other Property, Plant and Equipment	525.3	485.8
Accumulated Depreciation and Amortization	4,300.2	4,124.4
Other Noncurrent Assets
Securitized Transition Assets	240.6	258.7
Current Liabilities
Long-term Debt Due Within One Year	215.6	430.7
Accrued Interest	67.5	41.5
Noncurrent Liabilities
Long-term Debt	$ 4,147.3	$ 3,631.9
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	$ 2.5	$ 2.4
Fuel	39.8	37.3
Property, Plant and Equipment
Other Property, Plant and Equipment	607.2	583.8
Accumulated Depreciation and Amortization	3,280.5	3,151.6
Current Liabilities
Long-term Debt Due Within One Year	147.4	155.4
Accrued Interest	20.5	37.3
Noncurrent Liabilities
Long-term Debt	$ 2,884.1	$ 2,880
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	$ 68.8	$ 76.8
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	4.7	4.9
Restricted Cash	0	27.6
Property, Plant and Equipment
Other Property, Plant and Equipment	662.3	574.8
Accumulated Depreciation and Amortization	2,256.1	2,218.6
Other Noncurrent Assets
Securitized Transition Assets	0	12.9
Current Liabilities
Long-term Debt Due Within One Year	0.1	47.9
Accrued Interest	44.7	31.4
Noncurrent Liabilities
Long-term Debt	$ 2,113.8	$ 1,668.7
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	$ 0	$ 47.8
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	2.9	2
Fuel	12.8	12.3
Property, Plant and Equipment
Other Property, Plant and Equipment	319.6	303.5
Accumulated Depreciation and Amortization	1,558.5	1,472.9
Current Liabilities
Long-term Debt Due Within One Year	138.2	375.5
Noncurrent Liabilities
Long-term Debt	$ 1,248.2	$ 911.5
Equity
Common Stock, Par Value Per Share	$ 15	$ 15
Common Stock, Shares Authorized	11,000,000	11,000,000
Common Stock, Shares, Issued	10,482,000	10,482,000
Common Stock, Shares Outstanding	9,013,000	9,013,000
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 21.4	$ 24.5
Fuel	135.9	120.5
Property, Plant and Equipment
Other Property, Plant and Equipment	703.2	762.7
Accumulated Depreciation and Amortization	2,848.2	2,808.3
Current Liabilities
Long-term Debt Due Within One Year	121.2	59.7
Accrued Interest	22.9	34.7
Noncurrent Liabilities
Long-term Debt	$ 2,535.7	$ 2,653.7
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	$ 18.2	$ 22
Fuel	51.6	35.7
Property, Plant and Equipment
Other Property, Plant and Equipment	210.3	276.9
Accumulated Depreciation and Amortization	$ 105.7	$ 174.6

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Operating Activities
Net Income (Loss)	$ 1,767.1	$ 1,566.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	1,873.6	1,695.5
Deferred Income Taxes	15.9	43
Allowance for Equity Funds Used During Construction	(122.3)	(92.4)
Mark-to-Market of Risk Management Contracts	(41.6)	(95.4)
Amortization of Nuclear Fuel	71.6	82.6
Property Taxes	341.7	304.8
Deferred Fuel Over/Under-Recovery, Net	93.7	210.6
Recovery of Ohio Capacity Costs, Net	34.1	52.7
Refund of Global Settlement	(12.4)	(5.5)
Change in Other Noncurrent Assets	(9.6)	161.6
Change in Other Noncurrent Liabilities	(16.3)	141.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	125	(52.3)
Fuel, Materials and Supplies	(116.6)	98.7
Accounts Payable	(32.4)	(45)
Accrued Taxes, Net	(359.9)	(247.5)
Other Current Assets	60.2	11.7
Other Current Liabilities	(321.9)	101.1
Net Cash Flows from (Used for) Operating Activities	3,349.9	3,932.6
Investing Activities
Construction Expenditures	(4,336)	(4,688.4)
Acquisitions of Assets	(921.3)	0
Purchases of Investment Securities	(951.5)	(1,591.2)
Sales of Investment Securities	874.2	1,550.9
Acquisitions of Nuclear Fuel	(91.9)	(26.1)
Other Investing Activities	68.9	66.1
Net Cash Flows from (Used for) Investing Activities	(5,357.6)	(4,688.7)
Financing Activities
Issuance of Common Stock, Net	44.7	62.5
Issuance of Long-term Debt	3,492.4	3,572
Commercial Paper and Credit Facility Borrowings	0	205.6
Change in Short-term Debt, Net	600	604
Retirement of Long-term Debt	(1,023.5)	(1,959.5)
Commercial Paper and Credit Facility Repayments	0	(205.6)
Make Whole Premium on Extinguishment of Long-term Debt	(5)	(10.3)
Principal Payments for Finance Leases	(44.5)	(49.4)
Dividends Paid on Common Stock	(1,002)	(922.5)
Other Financing Activities	(8.7)	(15.8)
Net Cash Flows from (Used for) Financing Activities	2,053.4	1,281
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	45.7	524.9
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	444.1	412.6
Cash and Cash Equivalents at Beginning of Period	234.1
Cash, Cash Equivalents and Restricted Cash at End of Period	489.8	937.5
Cash and Cash Equivalents at End of Period	348.8
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	689.7	631.3
Net Cash Paid (Received) for Income Taxes	22.8	(27.9)
Noncash Acquisitions Under Finance Leases	66.7	43.5
Construction Expenditures Included in Current Liabilities as of September 30,	1,018.9	882.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	0	12.1
Noncash Contribution of Assets by Noncontrolling Interest	0	84
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	0	2.1
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed	32.4	0
AEP Texas Inc. [Member]
Operating Activities
Net Income (Loss)	192	151.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	464.8	364.9
Deferred Income Taxes	(0.6)	(21.2)
Allowance for Equity Funds Used During Construction	(8.3)	(15.2)
Mark-to-Market of Risk Management Contracts	0.2	0
Change in Other Noncurrent Assets	0.5	(55.7)
Change in Other Noncurrent Liabilities	6.5	67.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(50)	(26.5)
Fuel, Materials and Supplies	(0.1)	(2.4)
Accounts Payable	17.8	(19.1)
Accrued Taxes, Net	(33.4)	40
Other Current Assets	(0.7)	(6.3)
Other Current Liabilities	(12.9)	14.1
Net Cash Flows from (Used for) Operating Activities	575.8	490.8
Investing Activities
Construction Expenditures	(954.5)	(1,096.1)
Change in Advances to Affiliates, Net	0.3	103.9
Other Investing Activities	18.4	31.1
Net Cash Flows from (Used for) Investing Activities	(935.8)	(961.1)
Financing Activities
Capital Contributions from Parent	200	100
Issuance of Long-term Debt	627.5	494
Change in Advances from Affiliates, Net	(141.2)	77.8
Retirement of Long-term Debt	(366.8)	(231.7)
Principal Payments for Finance Leases	(3.8)	(3.6)
Other Financing Activities	(1.1)	0.9
Net Cash Flows from (Used for) Financing Activities	314.6	437.4
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(45.4)	(32.9)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	159.8	157.2
Cash and Cash Equivalents at Beginning of Period	3.1
Cash, Cash Equivalents and Restricted Cash at End of Period	114.4	124.3
Cash and Cash Equivalents at End of Period	0.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	95.1	92.2
Net Cash Paid (Received) for Income Taxes	28.7	(14.2)
Noncash Acquisitions Under Finance Leases	6.9	8.9
Construction Expenditures Included in Current Liabilities as of September 30,	183.6	176.4
AEP Transmission Co [Member]
Operating Activities
Net Income (Loss)	347.9	244.2
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	128.4	97.5
Deferred Income Taxes	36.7	76.3
Allowance for Equity Funds Used During Construction	(61.1)	(48.7)
Property Taxes	110.7	86.9
Long-term Accounts Receivable - Affiliated	(4.8)	(3.1)
Change in Other Noncurrent Assets	5.8	12.7
Change in Other Noncurrent Liabilities	(3.8)	18
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(5.1)	23.5
Fuel, Materials and Supplies	3.9	(2.8)
Accounts Payable	4.1	3.3
Accrued Taxes, Net	(92.8)	(73.2)
Accrued Interest	23.8	20.9
Other Current Assets	(1)	(0.5)
Other Current Liabilities	(8.5)	(28)
Net Cash Flows from (Used for) Operating Activities	484.2	427
Investing Activities
Construction Expenditures	(959.9)	(1,171.8)
Change in Advances to Affiliates, Net	(178.3)	(131.7)
Acquisitions of Assets	(7.6)	(13.2)
Other Investing Activities	12	1.2
Net Cash Flows from (Used for) Investing Activities	(1,133.8)	(1,315.5)
Financing Activities
Capital Contributions from Parent	0	582
Issuance of Long-term Debt	685.9	321.1
Change in Advances from Affiliates, Net	(36.3)	(14.6)
Principal Payments for Finance Leases	0
Net Cash Flows from (Used for) Financing Activities	649.6	888.5
Net Increase (Decrease) in Cash and Cash Equivalents	0	0
Cash and Cash Equivalents at Beginning of Period	0	0
Cash and Cash Equivalents at End of Period	0	0
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	43	38.4
Net Cash Paid (Received) for Income Taxes	29.8	(32.1)
Construction Expenditures Included in Current Liabilities as of September 30,	315.1	237
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	293.5	290
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	348.3	319.5
Deferred Income Taxes	(101.9)	(83.8)
Carrying Costs Income	0	(1.2)
Allowance for Equity Funds Used During Construction	(12.5)	(9.6)
Mark-to-Market of Risk Management Contracts	2.2	(43.7)
Deferred Fuel Over/Under-Recovery, Net	60.8	12.8
Change in Other Noncurrent Assets	6.7	94.8
Change in Other Noncurrent Liabilities	(29.6)	3.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	61.7	39.4
Fuel, Materials and Supplies	(49.2)	53
Accounts Payable	40.1	(21.5)
Accrued Taxes, Net	(30.2)	(20.2)
Other Current Assets	6.8	(7.9)
Other Current Liabilities	(25.1)	64.1
Net Cash Flows from (Used for) Operating Activities	571.6	690.7
Investing Activities
Construction Expenditures	(607.1)	(575.8)
Change in Advances to Affiliates, Net	0.3	0.4
Other Investing Activities	22.8	10
Net Cash Flows from (Used for) Investing Activities	(584)	(565.4)
Financing Activities
Issuance of Long-term Debt	478.2	103.3
Change in Advances from Affiliates, Net	(165.2)	(87.5)
Retirement of Long-term Debt	(180.4)	(24)
Principal Payments for Finance Leases	(5)	(5.2)
Dividends Paid on Common Stock	(125)	(120)
Other Financing Activities	0.6	1
Net Cash Flows from (Used for) Financing Activities	3.2	(132.4)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(9.2)	(7.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	29.8	19.2
Cash and Cash Equivalents at Beginning of Period	4.2
Cash, Cash Equivalents and Restricted Cash at End of Period	20.6	12.1
Cash and Cash Equivalents at End of Period	3.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	120.6	104.5
Net Cash Paid (Received) for Income Taxes	58.7	26.7
Noncash Acquisitions Under Finance Leases	7.1	3.9
Construction Expenditures Included in Current Liabilities as of September 30,	134.2	87.6
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	248	231.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	261.6	207.1
Rent - Rockport Plant, Unit 2	(58.9)	0
Deferred Income Taxes	(29.9)	28.1
Deferral of Incremental Nuclear Refueling Outage Expenses, Net	(11.6)	13.5
Allowance for Equity Funds Used During Construction	(16.4)	(8)
Mark-to-Market of Risk Management Contracts	(1.6)	(0.3)
Amortization of Nuclear Fuel	71.6	82.6
Deferred Fuel Over/Under-Recovery, Net	(20)	29.6
Change in Other Noncurrent Assets	46	(12)
Change in Other Noncurrent Liabilities	13.8	46.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	50.5	6.5
Fuel, Materials and Supplies	(4.6)	(1.1)
Accounts Payable	(7.3)	(34.7)
Accrued Taxes, Net	(49.4)	(7.1)
Payments for Rockport Plant, Unit 2 Operating Lease	(36.9)	0
Other Current Assets	7.8	4.9
Other Current Liabilities	(49.7)	(15.7)
Net Cash Flows from (Used for) Operating Activities	530.8	571.3
Investing Activities
Construction Expenditures	(431.7)	(434.5)
Change in Advances to Affiliates, Net	(0.5)	(60.1)
Purchases of Investment Securities	(915.7)	(1,589)
Sales of Investment Securities	871.4	1,550.9
Acquisitions of Nuclear Fuel	(91.9)	(26.1)
Other Investing Activities	10.5	9.2
Net Cash Flows from (Used for) Investing Activities	(557.9)	(549.6)
Financing Activities
Issuance of Long-term Debt	62.9	1,168.1
Change in Advances from Affiliates, Net	101.3	(211.6)
Retirement of Long-term Debt	(73.6)	(856.1)
Principal Payments for Finance Leases	(4)	(7.3)
Dividends Paid on Common Stock	(60)	(105.5)
Other Financing Activities	0.6	(9)
Net Cash Flows from (Used for) Financing Activities	27.2	(21.4)
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	0.3
Cash and Cash Equivalents at Beginning of Period	2.4	1.3
Cash and Cash Equivalents at End of Period	2.5	1.6
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	98.7	104.4
Net Cash Paid (Received) for Income Taxes	40.2	(26.5)
Noncash Acquisitions Under Finance Leases	8.1	4.4
Construction Expenditures Included in Current Liabilities as of September 30,	76.3	66.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	0	12.1
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	0	2.1
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	247.7	237.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	176.8	200.3
Amortization Of Generation Deferrals	65.3	171.9
Deferred Income Taxes	16.8	(71.9)
Carrying Costs Income	(0.7)	(1.5)
Allowance for Equity Funds Used During Construction	(14.1)	(7.8)
Mark-to-Market of Risk Management Contracts	13.3	(37.1)
Property Taxes	197.7	191.1
Refund of Global Settlement	(12.4)	(5.5)
Reversal of a Regulatory Provision	(56.2)	0
Change in Regulatory Assets	(28.1)	180.9
Change in Other Noncurrent Assets	(19.4)	0.8
Change in Other Noncurrent Liabilities	(51.1)	62.5
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	90	21.3
Fuel, Materials and Supplies	(9.6)	(3.7)
Accounts Payable	(12.3)	(31.8)
Accrued Taxes, Net	(245.9)	(210.6)
Other Current Assets	(9)	7.6
Other Current Liabilities	(40)	(4.3)
Net Cash Flows from (Used for) Operating Activities	309.5	700.8
Investing Activities
Construction Expenditures	(570.6)	(538.5)
Other Investing Activities	20	15.5
Net Cash Flows from (Used for) Investing Activities	(550.6)	(523)
Financing Activities
Issuance of Long-term Debt	444.3	392.8
Change in Advances from Affiliates, Net	(96.5)	155.1
Retirement of Long-term Debt	(48)	(397)
Principal Payments for Finance Leases	(2.6)	(2.9)
Dividends Paid on Common Stock	(85)	(337.5)
Other Financing Activities	1.1	0.7
Net Cash Flows from (Used for) Financing Activities	213.3	(188.8)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(27.8)	(11)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	32.5	29.7
Cash and Cash Equivalents at Beginning of Period	4.9
Cash, Cash Equivalents and Restricted Cash at End of Period	4.7	18.7
Cash and Cash Equivalents at End of Period	4.7
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	61.3	67.3
Net Cash Paid (Received) for Income Taxes	25.7	54.1
Noncash Acquisitions Under Finance Leases	8.6	3
Construction Expenditures Included in Current Liabilities as of September 30,	99.9	66
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	148.4	89.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	125.4	120.5
Deferred Income Taxes	(9.7)	(13.4)
Allowance for Equity Funds Used During Construction	(1.5)	0.3
Mark-to-Market of Risk Management Contracts	(12)	(11.5)
Property Taxes	(9.6)	(9.6)
Deferred Fuel Over/Under-Recovery, Net	49.8	73.3
Change in Other Noncurrent Assets	4.6	6.9
Change in Other Noncurrent Liabilities	(0.2)	14.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	9.1	(3.4)
Fuel, Materials and Supplies	(1.9)	(1.5)
Accounts Payable	(5.8)	6.9
Accrued Taxes, Net	19	38.4
Other Current Assets	(2.4)	0.3
Other Current Liabilities	1.1	15.1
Net Cash Flows from (Used for) Operating Activities	314.3	326.7
Investing Activities
Construction Expenditures	(198.7)	(162.8)
Change in Advances to Affiliates, Net	(95.1)	0
Other Investing Activities	2.1	3.9
Net Cash Flows from (Used for) Investing Activities	(291.7)	(158.9)
Financing Activities
Issuance of Long-term Debt	349.8	0
Change in Advances from Affiliates, Net	(105.5)	(127.6)
Retirement of Long-term Debt	(250.4)	(0.3)
Make Whole Premium on Extinguishment of Long-term Debt	(3)	0
Principal Payments for Finance Leases	(2.2)	(2.5)
Dividends Paid on Common Stock	(11.3)	(37.5)
Other Financing Activities	0.9	0.4
Net Cash Flows from (Used for) Financing Activities	(21.7)	(167.5)
Net Increase (Decrease) in Cash and Cash Equivalents	0.9	0.3
Cash and Cash Equivalents at Beginning of Period	2	1.6
Cash and Cash Equivalents at End of Period	2.9	1.9
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	46.5	42
Net Cash Paid (Received) for Income Taxes	16	1.6
Noncash Acquisitions Under Finance Leases	3.4	2.3
Construction Expenditures Included in Current Liabilities as of September 30,	31.5	24.3
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)	147.6	141.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	187.1	175.9
Deferred Income Taxes	(15.9)	2
Allowance for Equity Funds Used During Construction	(4.5)	(3.8)
Mark-to-Market of Risk Management Contracts	(2.5)	2.5
Property Taxes	(16.1)	(15.8)
Deferred Fuel Over/Under-Recovery, Net	14.1	4.4
Provision for Refund	(25.3)	0
Change in Other Noncurrent Assets	3.5	(8.9)
Change in Other Noncurrent Liabilities	5.8	52.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(17.2)	44.3
Fuel, Materials and Supplies	(17.7)	5
Accounts Payable	(12.8)	(29.9)
Accrued Taxes, Net	54.1	38.4
Other Current Assets	(4.5)	3.2
Other Current Liabilities	(13.9)	4.2
Net Cash Flows from (Used for) Operating Activities	307.1	415.3
Investing Activities
Construction Expenditures	(277.3)	(336.6)
Change in Advances to Affiliates, Net	74.9	(516.6)
Other Investing Activities	(1.2)	1.2
Net Cash Flows from (Used for) Investing Activities	(203.6)	(852)
Financing Activities
Issuance of Long-term Debt	0	1,015.4
Change in Short-term Debt, Net	0	(2.6)
Change in Advances from Affiliates, Net	0	(118.7)
Retirement of Long-term Debt	(58.2)	(385.3)
Principal Payments for Finance Leases	(8.1)	(8.5)
Dividends Paid on Common Stock	(37.5)	(60)
Dividends Paid on Common Stock	(3.3)	(3.2)
Other Financing Activities	0.5	0.5
Net Cash Flows from (Used for) Financing Activities	(106.6)	437.6
Net Increase (Decrease) in Cash and Cash Equivalents	(3.1)	0.9
Cash and Cash Equivalents at Beginning of Period	24.5	1.6
Cash and Cash Equivalents at End of Period	21.4	2.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	95.1	102.5
Net Cash Paid (Received) for Income Taxes	7.3	12.9
Noncash Acquisitions Under Finance Leases	4.7	3.2
Construction Expenditures Included in Current Liabilities as of September 30,	52	37
Noncontrolling Interest [Member]
Supplementary Information
Noncash Contribution of Assets by Noncontrolling Interest	$ 253.4
Noncontrolling Interest [Member] | AEP Wind Holdings LLC [Member]
Supplementary Information
Noncash Contribution of Assets by Noncontrolling Interest		$ 0

Significant Accounting Matters

Significant Accounting Matters	9 Months Ended
	Sep. 30, 2019
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2019 is not necessarily indicative of results that may be expected for the year ending December 31, 2019 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2018 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 21, 2019 . 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 awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2019 2018 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 733.5 $ 577.6 Weighted Average Number of Basic Shares Outstanding 493.8 $ 1.49 493.0 $ 1.17 Weighted Average Dilutive Effect of Stock-Based Awards 1.7 (0.01 ) 0.9 — Weighted Average Number of Diluted Shares Outstanding 495.5 $ 1.48 493.9 $ 1.17 Nine Months Ended September 30, 2019 2018 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,767.6 $ 1,560.4 Weighted Average Number of Basic Shares Outstanding 493.6 $ 3.58 492.6 $ 3.17 Weighted Average Dilutive Effect of Stock-Based Awards 1.5 (0.01 ) 0.9 (0.01 ) Weighted Average Number of Diluted Shares Outstanding 495.1 $ 3.57 493.5 $ 3.16 Equity Units issued in March 2019 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2019 , as the dilutive stock price threshold was not met. See Note 13 - Financing Activities for more information related to Equity Units. There were no antidilutive shares outstanding as of September 30, 2019 and 2018 . Restricted Cash (Applies to AEP, AEP Texas, APCo and OPCo) Restricted Cash primarily included funds held by trustee for the payment of securitization bonds and contractually restricted deposits held for the future payment of the remaining construction activities at Santa Rita East. 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 sheets that sum to the total of the same amounts shown on the statements of cash flows: September 30, 2019 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 348.8 $ 0.1 $ 3.5 $ 4.7 Restricted Cash 141.0 114.3 17.1 — Total Cash, Cash Equivalents and Restricted Cash $ 489.8 $ 114.4 $ 20.6 $ 4.7 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

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2019
New Accounting Pronouncements	ACCOUNTING STANDARDS The disclosures in this note apply to all Registrants unless indicated otherwise. During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following standards will impact the financial statements. 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, capital leases are known as finance leases going forward. Leases with terms of 12 months or longer are also subject to the new requirements. Fundamentally, the criteria used to determine lease classification remains the same, but is 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 sheets. 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 sheets. See Note 12 - Leases for additional disclosures required by the new standard. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring the recognition of an allowance for expected credit losses for financial instruments within its scope. Examples of financial instruments that are in scope include trade receivables, certain financial guarantees, and held-to-maturity debt securities. The allowance for expected credit losses should be based on historical information, current conditions and reasonable and supportable forecasts. The new standard also revises the other-than-temporary impairment model for available-for-sale debt securities. 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 continues to analyze the impact of this new standard. Implementation activities to date include the identification of the population of financial instruments within the AEP system that are subject to the new standard and evaluations to determine whether the new expected loss recognition model will cause any material changes to previously calculated allowance balances and supporting valuation models. Based on the assessments performed to date, Management does not expect the new standard to have a material impact on results of operations, financial position or cash flows. Management’s implementation activities, including an assessment of the new standard’s disclosure requirements will continue throughout the fourth quarter of 2019. Management will continue to analyze the related impacts to allowances for credit losses and monitor for any potential industry implementation issues. Additionally, Management does not anticipate any significant changes to current accounting systems because of the adoption of the new standard. Management plans to adopt ASU 2016-13 and its related implementation guidance effective January 1, 2020.

Comprehensive Income

Comprehensive Income	9 Months Ended
	Sep. 30, 2019
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details. AEP Cash Flow Hedges Pension Three Months Ended September 30, 2019 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (127.2 ) $ (15.9 ) $ (87.6 ) $ (230.7 ) Change in Fair Value Recognized in AOCI 38.4 (0.8 ) (b) — 37.6 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — (0.1 ) Purchased Electricity for Resale (a) 8.5 — — 8.5 Amortization of Prior Service Cost (Credit) — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains) Losses — — 3.0 3.0 Reclassifications from AOCI, before Income Tax (Expense) Benefit 8.4 — (1.8 ) 6.6 Income Tax (Expense) Benefit 1.8 — (0.4 ) 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 6.6 — (1.4 ) 5.2 Net Current Period Other Comprehensive Income (Loss) 45.0 (0.8 ) (1.4 ) 42.8 Balance in AOCI as of September 30, 2019 $ (82.2 ) $ (16.7 ) $ (89.0 ) $ (187.9 ) Cash Flow Hedges Pension Three Months Ended September 30, 2018 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (30.4 ) $ (15.3 ) $ (49.1 ) $ (94.8 ) Change in Fair Value Recognized in AOCI 12.2 2.3 — 14.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — (0.1 ) Purchased Electricity for Resale (a) (5.8 ) — — (5.8 ) Interest Expense (a) — 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains) Losses — — 3.2 3.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit (5.9 ) 0.4 (1.8 ) (7.3 ) Income Tax (Expense) Benefit (1.3 ) 0.1 (0.4 ) (1.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (4.6 ) 0.3 (1.4 ) (5.7 ) Net Current Period Other Comprehensive Income (Loss) 7.6 2.6 (1.4 ) 8.8 Balance in AOCI as of September 30, 2018 $ (22.8 ) $ (12.7 ) $ (50.5 ) $ (86.0 ) AEP Cash Flow Hedges Pension Nine Months Ended September 30, 2019 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (23.0 ) $ (12.6 ) $ (84.8 ) $ (120.4 ) Change in Fair Value Recognized in AOCI (92.3 ) (4.5 ) (b) — (96.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — (0.1 ) Purchased Electricity for Resale (a) 42.0 — — 42.0 Interest Expense (a) — 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — — (14.3 ) (14.3 ) Amortization of Actuarial (Gains) Losses — — 9.0 9.0 Reclassifications from AOCI, before Income Tax (Expense) Benefit 41.9 0.5 (5.3 ) 37.1 Income Tax (Expense) Benefit 8.8 0.1 (1.1 ) 7.8 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 33.1 0.4 (4.2 ) 29.3 Net Current Period Other Comprehensive Income (Loss) (59.2 ) (4.1 ) (4.2 ) (67.5 ) Balance in AOCI as of September 30, 2019 $ (82.2 ) $ (16.7 ) $ (89.0 ) $ (187.9 ) Cash Flow Hedges Securities Interest Available Pension Nine Months Ended September 30, 2018 Commodity Rate for Sale and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (28.4 ) $ (13.0 ) $ 11.9 $ (38.3 ) $ (67.8 ) Change in Fair Value Recognized in AOCI 30.4 2.3 — — 32.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — — (0.1 ) Purchased Electricity for Resale (a) (23.6 ) — — — (23.6 ) Interest Expense (a) — 0.9 — — 0.9 Amortization of Prior Service Cost (Credit) — — — (14.7 ) (14.7 ) Amortization of Actuarial (Gains) Losses — — — 9.6 9.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit (23.7 ) 0.9 — (5.1 ) (27.9 ) Income Tax (Expense) Benefit (5.0 ) 0.2 — (1.1 ) (5.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (18.7 ) 0.7 — (4.0 ) (22.0 ) Net Current Period Other Comprehensive Income (Loss) 11.7 3.0 — (4.0 ) 10.7 ASU 2018-02 Adoption (6.1 ) (2.7 ) — (8.2 ) (17.0 ) ASU 2016-01 Adoption — — (11.9 ) — (11.9 ) Balance in AOCI as of September 30, 2018 $ (22.8 ) $ (12.7 ) $ — $ (50.5 ) $ (86.0 ) AEP Texas Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (3.9 ) $ (10.6 ) $ (14.5 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (0.1 ) (0.1 ) Amortization of Actuarial (Gains) Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit — — — Income Tax (Expense) Benefit — — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — — — Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2019 $ (3.6 ) $ (10.6 ) $ (14.2 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (4.9 ) $ (9.8 ) $ (14.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4 — 0.4 Income Tax (Expense) Benefit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3 — 0.3 Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2018 $ (4.6 ) $ (9.8 ) $ (14.4 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (4.4 ) $ (10.7 ) $ (15.1 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.1 ) (0.1 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.6 0.1 0.7 Income Tax (Expense) Benefit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.5 0.1 0.6 Net Current Period Other Comprehensive Income (Loss) 0.8 0.1 0.9 Balance in AOCI as of September 30, 2019 $ (3.6 ) $ (10.6 ) $ (14.2 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (4.5 ) $ (8.1 ) $ (12.6 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.1 ) (0.1 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0 0.1 1.1 Income Tax (Expense) Benefit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8 0.1 0.9 Net Current Period Other Comprehensive Income (Loss) 0.8 0.1 0.9 ASU 2018-02 Adoption (0.9 ) (1.8 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (4.6 ) $ (9.8 ) $ (14.4 ) APCo Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ 1.4 $ (8.1 ) $ (6.7 ) Change in Fair Value Recognized in AOCI (0.3 ) — (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains) Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit — (0.8 ) (0.8 ) Income Tax (Expense) Benefit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — (0.6 ) (0.6 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) (0.6 ) (0.9 ) Balance in AOCI as of September 30, 2019 $ 1.1 $ (8.7 ) $ (7.6 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ 2.3 $ (2.7 ) $ (0.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.4 ) — (0.4 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains) Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.4 ) (0.9 ) (1.3 ) Income Tax (Expense) Benefit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3 ) (0.7 ) (1.0 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) (0.7 ) (1.0 ) Balance in AOCI as of September 30, 2018 $ 2.0 $ (3.4 ) $ (1.4 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ 1.8 $ (6.8 ) $ (5.0 ) Change in Fair Value Recognized in AOCI (0.3 ) — (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.5 ) — (0.5 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains) Losses — 1.6 1.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.5 ) (2.4 ) (2.9 ) Income Tax (Expense) Benefit (0.1 ) (0.5 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.4 ) (1.9 ) (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) (1.9 ) (2.6 ) Balance in AOCI as of September 30, 2019 $ 1.1 $ (8.7 ) $ (7.6 ) Cash Flow Hedges Pension Nine Months Ended September 30, 2018 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ — $ 2.2 $ (0.9 ) $ 1.3 Change in Fair Value Recognized in AOCI (0.7 ) — — (0.7 ) Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (a) 0.9 — — 0.9 Interest Expense (a) — (0.9 ) — (0.9 ) Amortization of Prior Service Cost (Credit) — — (3.9 ) (3.9 ) Amortization of Actuarial (Gains) Losses — — 1.0 1.0 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.9 (0.9 ) (2.9 ) (2.9 ) Income Tax (Expense) Benefit 0.2 (0.2 ) (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.7 (0.7 ) (2.3 ) (2.3 ) Net Current Period Other Comprehensive Income (Loss) — (0.7 ) (2.3 ) (3.0 ) ASU 2018-02 Adoption — 0.5 (0.2 ) 0.3 Balance in AOCI as of September 30, 2018 $ — $ 2.0 $ (3.4 ) $ (1.4 ) I&M Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (10.7 ) $ (2.4 ) $ (13.1 ) Change in Fair Value Recognized in AOCI 0.4 — 0.4 Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit — — — Income Tax (Expense) Benefit — — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — — — Net Current Period Other Comprehensive Income (Loss) 0.4 — 0.4 Balance in AOCI as of September 30, 2019 $ (10.3 ) $ (2.4 ) $ (12.7 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (12.2 ) $ (1.7 ) $ (13.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4 — 0.4 Income Tax (Expense) Benefit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3 — 0.3 Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2018 $ (11.9 ) $ (1.7 ) $ (13.6 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (11.5 ) $ (2.3 ) $ (13.8 ) Change in Fair Value Recognized in AOCI 0.4 — 0.4 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains) Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0 (0.1 ) 0.9 Income Tax (Expense) Benefit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8 (0.1 ) 0.7 Net Current Period Other Comprehensive Income (Loss) 1.2 (0.1 ) 1.1 Balance in AOCI as of September 30, 2019 $ (10.3 ) $ (2.4 ) $ (12.7 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (10.7 ) $ (1.4 ) $ (12.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains) Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.5 — 1.5 Income Tax (Expense) Benefit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.2 — 1.2 ASU 2018-02 Adoption (2.4 ) (0.3 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (11.9 ) $ (1.7 ) $ (13.6 ) OPCo Cash Flow Hedge – Three Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of June 30, 2019 $ 0.3 Change in Fair Value Recognized in AOCI (0.2 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.1 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1 ) Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) Balance in AOCI as of September 30, 2019 $ — Cash Flow Hedge – Three Months Ended September 30, 2018 Interest Rate (in millions) Balance in AOCI as of June 30, 2018 $ 1.7 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.5 ) Income Tax (Expense) Benefit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.4 ) Balance in AOCI as of September 30, 2018 $ 1.3 Cash Flow Hedge – Nine Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of December 31, 2018 $ 1.0 Change in Fair Value Recognized in AOCI (0.2 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.0 ) Income Tax (Expense) Benefit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (1.0 ) Balance in AOCI as of September 30, 2019 $ — Cash Flow Hedge – Nine Months Ended September 30, 2018 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) (1.3 ) 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 0.4 Balance in AOCI as of September 30, 2018 $ 1.3 PSO Cash Flow Hedge – Three Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of June 30, 2019 $ 1.6 Change in Fair Value Recognized in AOCI (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.2 Income Tax (Expense) Benefit 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.1 Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2019 $ 1.4 Cash Flow Hedge – Three Months Ended September 30, 2018 Interest Rate (in millions) Balance in AOCI as of June 30, 2018 $ 2.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.2 ) Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2 ) Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2018 $ 2.4 Cash Flow Hedge – Nine Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of December 31, 2018 $ 2.1 Change in Fair Value Recognized in AOCI (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.5 ) Income Tax (Expense) Benefit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) Balance in AOCI as of September 30, 2019 $ 1.4 Cash Flow Hedge – Nine Months Ended September 30, 2018 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) (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.9 ) Income Tax (Expense) Benefit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.7 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) ASU 2018-02 Adoption 0.5 Balance in AOCI as of September 30, 2018 $ 2.4 SWEPCo Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (2.5 ) $ (2.7 ) $ (5.2 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit — (0.3 ) (0.3 ) Income Tax (Expense) Benefit — — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — (0.3 ) (0.3 ) Net Current Period Other Comprehensive Income (Loss) 0.3 (0.3 ) — Balance in AOCI as of September 30, 2019 $ (2.2 ) $ (3.0 ) $ (5.2 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (6.4 ) $ 1.7 $ (4.7 ) Change in Fair Value Recognized in AOCI 2.3 — 2.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains) Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5 (0.4 ) 0.1 Income Tax (Expense) Benefit 0.1 (0.1 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4 (0.3 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 2.7 (0.3 ) 2.4 Balance in AOCI as of September 30, 2018 $ (3.7 ) $ 1.4 $ (2.3 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (3.3 ) $ (2.1 ) $ (5.4 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains) Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0 (1.1 ) (0.1 ) Income Tax (Expense) Benefit 0.2 (0.2 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8 (0.9 ) (0.1 ) Net Current Period Other Comprehensive Income (Loss) 1.1 (0.9 ) 0.2 Balance in AOCI as of September 30, 2019 $ (2.2 ) $ (3.0 ) $ (5.2 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 2.0 $ (4.0 ) Change in Fair Value Recognized in AOCI 2.3 — 2.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.6 — 1.6 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.6 (1.3 ) 0.3 Income Tax (Expense) Benefit 0.3 (0.3 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.3 (1.0 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 3.6 (1.0 ) 2.6 ASU 2018-02 Adoption (1.3 ) 0.4 (0.9 ) Balance in AOCI as of September 30, 2018 $ (3.7 ) $ 1.4 $ (2.3 ) (a) Amounts reclassified to the referenced line item on the statements of income. (b) The change in fair value includes $2 million and $6 million

Rate Matters

Rate Matters	9 Months Ended
	Sep. 30, 2019
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2018 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2018 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2019 and updates the 2018 Annual Report. 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 September 30, 2019 . See “2018 Oklahoma Base Rate Case” below for additional information. Gross Accumulated Net Accelerated Materials and Supplies Cost of Expected Remaining (dollars in millions) $ 106.6 $ 80.6 $ 26.0 $ 21.9 $ 3.2 $ 5.1 2020 27 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” discussion below for additional information. Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo) AEP September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs – Unrecovered Plant $ 50.3 $ 50.3 Kentucky Deferred Purchase Power Expenses 26.2 14.5 Oklaunion Power Station Accelerated Depreciation 21.9 5.5 Other Regulatory Assets Pending Final Regulatory Approval 5.4 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs – Asset Retirement Obligation Costs 37.8 35.3 Storm-Related Costs (a) — 152.4 Other Regulatory Assets Pending Final Regulatory Approval 26.8 20.7 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 168.4 $ 288.0 (a) In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information. (b) In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million , 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 Texas September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Rate Case Expense $ 2.3 $ 0.2 Storm-Related Costs (a) — 152.4 Total Regulatory Assets Pending Final Regulatory Approval $ 2.3 $ 152.6 (a) In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information. APCo September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs – Materials and Supplies $ 5.1 $ 9.0 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs – Asset Retirement Obligation Costs 37.8 35.3 Other Regulatory Assets Pending Final Regulatory Approval — 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 42.9 $ 44.9 (a) In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million , 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 September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Study Costs $ 10.7 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.1 3.3 Total Regulatory Assets Pending Final Regulatory Approval $ 10.8 $ 3.3 OPCo September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 1.0 Total Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 1.0 PSO September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Oklaunion Power Station Accelerated Depreciation $ 21.9 $ 5.5 Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval — 0.5 Total Regulatory Assets Pending Final Regulatory Approval $ 21.9 $ 6.0 SWEPCo September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs – Unrecovered Plant $ 50.3 $ 50.3 Other Regulatory Assets Pending Final Regulatory Approval 0.3 0.3 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation - Arkansas, Louisiana 6.8 5.3 Rate Case Expense – Texas 1.4 4.9 Other Regulatory Assets Pending Final Regulatory Approval 4.2 3.6 Total Regulatory Assets Pending Final Regulatory Approval $ 63.0 $ 64.4 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP and AEP Texas) AEP Texas Interim Transmission and Distribution Rates As of September 30, 2019 , AEP Texas’ cumulative revenues from interim transmission and distribution rate increases from 2008 through 2019, subject to review, are estimated to be $1.3 billion . The 2019 base rate case described below 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. 2019 Texas Base Rate Case In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% return on common equity. The filing includes a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to rate normalization requirements. The rate case also seeks a prudence determination on all capital additions included in interim rates from 2008. In July and August 2019, PUCT staff and various intervenors filed testimony. The PUCT staff recommended a $63 million annual rate reduction based on a 9.35% return on common equity while intervenors recommended annual rate reductions of up to $159 million based on a return on common equity ranging from 9% to 9.2%. The difference between AEP Texas’ requested annual base rate increase and the PUCT staff’s and various intervenor’s recommendations are primarily due to: (a) recommended capital structure of 60% debt and 40% common equity as compared to the 55% debt and 45% common equity requested by AEP Texas, (b) a reduction in the requested return on common equity and (c) various disallowances that could potentially result in write-offs exceeding $450 million. The PUCT staff's recommended disallowances primarily consisted of $85 million in capital incentives and $26 million for capitalized vegetation management expenses. The intervenors recommended disallowances primarily consisted of (a) $173 million for a newly constructed transmission operations center and other service centers, (b) $94 million for Hurricane Harvey costs, (c) $36 million for capitalized cross arms and (d) $21 million for capitalized plant costs related to unreimbursed damages to assets caused by third-parties. In addition, one intervenor recommended AEP Texas refund $115 million of Excess ADIT, which includes $2 million in interest, related to previously owned deregulated generation assets. AEP Texas recorded $113 million as a favorable adjustment to income tax expense in 2017 as a result of Tax Reform. Hearings were held in August 2019 and briefs were filed in September 2019. AEP Texas is expecting a Proposal for Decision from the ALJ in the fourth quarter of 2019. The PUCT is expected to issue an order on the case by the first quarter of 2020. If any of these costs are not recoverable or refunds of revenues collected under interim transmission and distribution rates are ordered to be returned to customers, it could reduce future net income and cash flows and impact financial condition. Texas Storm Cost Securitization In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT, which included estimated carrying costs. In June 2019, the PUCT approved the financing order. As part of the financing order, AEP Texas agreed to offset $64 million of Excess ADIT that is not subject to rate normalization requirements against the total distribution-related system restoration costs. In September 2019, AEP Texas issued $235 million of securitization bonds. The securitization bonds included carrying costs of $33 million, which includes $21 million of debt carrying costs recorded as a reduction to Interest Expense in 2019. The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered in the 2019 Texas Base Rate Case described above or through interim transmission base rate increases. 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 Under a 2015 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. The 2015 amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. New Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that requires APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). 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 to customers or be used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with asset impairments related to early retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the period recorded. 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. If the Virginia triennial review of APCo earnings results in any disallowance, it could 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 March 2019, the Virginia SCC issued an order to reduce APCo’s base rates to refund: (a) $40 million annually for ongoing annual tax savings, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM, (c) $94 million of Excess ADIT that is not subject to rate normalization requirements over three years and (d) a one-time credit of $22 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019. 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. In February 2019, the WVPSC issued an order approving a Stipulation and Settlement agreement between APCo, WPCo, WVPSC staff and certain intervenors. The agreement included an 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 also included: (a) $18 million ( $14 million related to APCo) of increased annual depreciation expense, (b) a $24 million refund ( $19 million related to APCo) over two years, through a rider beginning March 2019, of Excess ADIT that is not subject to rate normalization requirements, (c) the utilization of $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, (d) an agreement to seek WVPSC approval of economic incentive programs to provide funds to aid in industrial and commercial development and (e) an agreement, barring any unforeseen events, to not initiate another base rate proceeding prior to April 1, 2020. 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 September 30, 2019 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $987 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 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. I&M Rate Matters (Applies to AEP and I&M) Michigan Tax Reform In October 2018, I&M made a filing with the MPSC recommending to: (a) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (b) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over ten years. In September 2019, an ALJ issued a Proposal for Decision and various intervenors filed objections which included changing the refund period from ten years to seven years. In October 2019, I&M filed responses to the various intervenor objections. An order from the MPSC regarding Excess ADIT is expected in the fourth quarter of 2019. 2019 Indiana Base Rate Case In May 2019, I&M filed a request with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021 and is based upon a proposed 10.5% return on common equity. The proposed annual increase includes $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $52 million related to proposed investments and $26 million related to increased depreciation rates. The request includes the continuation of all existing riders and a new Automated Metering Infrastructure rider for proposed meter projects. In August 2019, various intervenors filed testimony that recommended annual rate increases ranging from $2 million to $33 million based upon a return on common equity ranging from 9% to 9.73%. The difference between I&M’s requested annual base rate increase and the intervenor’s recommendations are primarily due to: (a) proposed denial of return on and of certain new plant investments, (b) proposed lower depreciation rates, (c) a reduction in the requested return on common equity and (d) exclusion of I&M’s proposed re-allocation of capacity costs related to I&M’s June 2020 loss of a significant FERC wholesale contract. In addition, certain parties recommended disallowances that could potentially result in write-offs of $41 million related to the remaining book value of existing Indiana jurisdictional meters and $11 million associated with certain Cook Plant study costs. In September 2019, I&M filed testimony rebutting the various parties’ recommendations. A hearing at the IURC began in October 2019. The IURC is expected to issue an order on the case by the first quarter of 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2019 Michigan Base Rate Case In June 2019, I&M filed a request with the MPSC for a $58 million annual increase. The requested increase in Michigan rates would be phased in through June 2020 and is based upon a proposed 10.5% return on common equity. The proposed annual increase includes $19 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $13 million related to proposed investments and $6 million related to increased depreciation rates. The proposed annual increase also includes $10 million for annual lost revenue related to the Michigan Electric Customer Choice Program that began in 2019. In October 2019, MPSC staff and various intervenors filed testimony. The MPSC staff recommended a $38 million annual rate increase based upon a 9.75% return on common equity while intervenors recommended annual rate increases of up to $28 million based on a return on common equity ranging from 9.1% to 9.25%. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio ESP Filings ESP Extension through 2024 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 April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. In October 2019, oral arguments were held in the Ohio Supreme Court. If the Ohio Supreme Court reverses the PUCO’s decision, it could reduce future net income and cash flows and impact financial condition. OPCo’s Enhanced Service Reliability Rider (ESRR) authorized under the ESP is subject to annual audits. In May 2018, the PUCO staff filed comments indicating that 2016 spending under the ESRR was subject to authorized limits and that OPCo overspent those limits. OPCo filed reply comments objecting to the PUCO staff’s position, including the method of calculating the overspent amount. In March 2019, the PUCO staff filed additional comments which adjusted the method of the calculation but maintained that OPCo overspent the authorized limit in 2016 and 2017, which could result in a refund of $10 million . Management believes that both 2016 and 2017 ESRR spending is not subject to an authorized limit and that a spending limit was not established until 2018, as part of the ESP extension. A hearing was held in May 2019 to address the 2016 audit. Post-hearing briefs in this case were filed in June 2019 and reply briefs were filed in July 2019. If it is determined OPCo did have an authorized spending limit under the ESRR in 2016 and 2017, and refunds are ordered, it would 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 February 2019, the PUCO issued an order that OPCo did not have significantly excessive earnings in 2016. As a result of the order, OPCo reversed the $58 million provision in the first quarter of 2019. PSO Rate Matters (Applies to AEP and PSO) 2018 Oklahoma Base Rate Case In 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 included $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates included 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 March 2019, the OCC issued an order approving a Stipulation and Settlement agreement for a $46 million annual increase, based on a 9.4% return on equity effective with the first billing cycle of April 2019. The order also included agreements between the parties that: (a) depreciation rates will remain unchanged, (b) PSO will file a new base rate request no earlier than October 2020 and no later than October 2021 and (c) PSO will refund Excess ADIT that is not subject to rate normalization requirements over five years instead of the ten years ordered in the Oklahoma Tax Reform case. The order did not approve the performance-based rate plan but instead provided for an expansion of the SPP Transmission Tariff that tracks previously untracked SPP costs and a new Distribution Reliability and Safety Rider that provides additional revenues capped at $5 million per year for distribution projects related to safety and reliability that are not normal distribution replacements. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. The resulting annual base rate increase was approximately $52 million . In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In May 2019, various intervenors filed replies to the petition. In July 2019, SWEPCo filed its response to these replies. The Texas Supreme Court has requested full briefing by the parties. SWEPCo’s initial brief is due in October 2019. Response briefs are due in November 2019 and SWEPCo’s reply brief is due in December 2019. As of September 30, 2019 , the net book value of Turk Plant was $1.5 billion , before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6% , effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million , which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition. 2018 Louisiana Formula Rate Filing In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC. The filing included a net $28 million annual increase, which was effective August 2018 and included SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform but did not address the return of Excess ADIT benefits to customers. In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million . The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the return of Excess ADIT benefits to customers. In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. A decision by the LPSC on the remaining issues is expected in the fourth quarter of 2019. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $550 million , excluding AFUDC. As of September 30, 2019 , SWEPCo had incurred costs of $399 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2019 , the total net book value of Welsh Plant, Units 1 and 3 was $612 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In 2017, the LPSC approved recovery of $131 million

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2019
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2018 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below. Letters of Credit (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 September 30, 2019 , 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 six uncommitted facilities totaling $405 million . The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2019 were as follows: Company Amount Maturity (in millions) AEP $ 204.4 October 2019 to October 2020 AEP Texas 2.2 July 2020 OPCo 3.6 April 2020 to September 2020 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 $155 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 September 30, 2019 , SWEPCo has collected $77 million through a rider for reclamation costs, of which $83 million was recorded in Asset Retirement Obligations, offset by $6 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 September 30, 2019 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expired in October 2019. In April 2019, AEP acquired Sempra Renewables LLC. See “Acquisitions” section of Note 6 for additional information. 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 September 30, 2019 , 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. 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. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements. NUCLEAR CONTINGENCIES (Applies to AEP and I&M) I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In 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 by the U.S. District Court for the Southern District of Ohio 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. In 2017, 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. Thereafter, 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. 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. The consent decree was modified based on an agreement among the parties in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement. See “Modification of the New Source Review 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 cannot determine a range of potential losses that are reasonably possible of occurring. Patent Infringement Complaint In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. The complaint seeks injunctive relief and damages. Management will continue to defend against the claims. Management is unable to determine a range of potential loss that is reasonably possible of occurring.

Acquisitions and Impairments

Acquisitions and Impairments	9 Months Ended
	Sep. 30, 2019
Acquisitions and Impairments	ACQUISITIONS AND IMPAIRMENTS The disclosures in this note apply to AEP only unless indicated otherwise. ACQUISITIONS Sempra Renewables LLC (Generation & Marketing Segment) In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion . This acquisition is part of AEP’s strategy to grow its renewable generation portfolio and to diversify generation resources. AEP paid $583 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $ 406 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million . The purchase price, subject to working capital adjustments, was allocated as follows: Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019 Assets: Liabilities and Equity: Net Purchase Price (in millions) Current Assets $ 9.7 Current Liabilities $ 12.9 Property, Plant and Equipment 238.1 Asset Retirement Obligations 5.7 Investment in Joint Ventures 405.9 Total Liabilities 18.6 Other Noncurrent Assets 82.9 Noncontrolling Interest 134.8 Total Assets $ 736.6 Liabilities and Noncontrolling Interest $ 153.4 $ 583.2 Management allocated the purchase price based upon the relative fair value of the assets acquired and noncontrolling interests assumed. The fair value of the primary assets acquired and the noncontrolling interests assumed was determined using a discounted cash flow method under the income approach. The key input assumptions utilized in the determination of the fair value of these assets were the pricing and terms of the existing purchase power agreements, forecasted market power prices, forecasted PTCs from the wind farms, expected wind farm net capacity, forecasted cash benefits from income tax depreciation and discount rates reflecting risk inherent in the future cash flows and future power prices. Additional key input assumptions for the fair value of the noncontrolling interests include the terms of the limited liability company agreements that dictate the sharing of the tax attributes and cash flows associated with the tax equity partnerships. Under the accounting rules for acquisitions, AEP has one year to finalize the purchase price allocation, including working capital adjustments and other closing adjustments. Upon closing of the purchase, Sempra Renewables LLC was legally renamed AEP Wind Holdings LLC. AEP Wind Holdings LLC develops, owns and operates, or holds interests in, wind generation facilities in the United States. The operating wind generation portfolio includes seven wind farms. Five wind farms are jointly-owned with BP Wind Energy, and two wind farms are consolidated by AEP and are tax equity partnerships with nonaffiliated noncontrolling interests. All seven wind farms have long-term PPAs for 100% of their energy production. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production which totaled $2 million and $3 million , respectively, of purchased electricity for the three months ended September 30, 2019 , and $5 million and $10 million , respectively, for the nine months ended September 30, 2019 . Another joint venture wind farm has a PPA with SWEPCo for a portion of its energy production which totaled $3 million and $6 million of purchased electricity for the three and nine months ended September 30, 2019 , respectively. The PPAs with I&M, OPCo and SWEPCo were executed prior to the acquisition of the wind farms and will be accounted for in accordance with the accounting guidance for “Related Parties.” Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of September 30, 2019 , the maximum potential amount of future payments associated with these guarantees was $186 million , with the last guarantee expiring in December 2037. The liability recorded associated with these guarantees was $34 million as of September 30, 2019 . The acquired business contributed revenues and Net Income to AEP that were not material for the period April 22, 2019 to September 30, 2019 . The pro-forma revenue and net income related to the acquisition of Sempra Renewables LLC were not material for the three and nine months ended September 30, 2019 and 2018 . See Note 14 - Variable Interest Entities and Equity Method Investments for additional information related to the purchased wind farms. Santa Rita East (Generation & Marketing Segment) In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million . In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Santa Rita East represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of Santa Rita East, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Santa Rita East and recent third-party market transactions for similar wind farms. See “Santa Rita East” section of Note 14 for additional information. IMPAIRMENTS 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. 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. Due to weather-related delays in the first quarter of 2019, reconstruction activities at Racine are now estimated to be completed in the first half of 2020. AEP expects to incur additional capital expenditures to complete the reconstruction project, at which point the fair value of Racine, as fully operational, is expected to approximate the book value once complete. Future revisions in cost estimates or delays in completion could result in additional losses which could reduce future net income and cash flows and impact financial condition.

Benefit Plans

Benefit Plans	9 Months Ended
	Sep. 30, 2019
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 23.8 $ 24.4 $ 2.4 $ 2.9 Interest Cost 51.1 46.9 12.6 11.8 Expected Return on Plan Assets (74.0 ) (72.6 ) (23.4 ) (25.6 ) Amortization of Prior Service Credit — — (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 14.4 21.3 5.5 2.7 Net Periodic Benefit Cost (Credit) $ 15.3 $ 20.0 $ (20.2 ) $ (25.5 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 71.6 $ 73.2 $ 7.1 $ 8.7 Interest Cost 153.3 140.8 37.9 35.5 Expected Return on Plan Assets (222.0 ) (217.7 ) (70.3 ) (76.7 ) Amortization of Prior Service Credit — — (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 43.2 63.9 16.6 7.9 Net Periodic Benefit Cost (Credit) $ 46.1 $ 60.2 $ (60.5 ) $ (76.4 ) AEP Texas Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 2.2 $ 2.3 $ 0.1 $ 0.3 Interest Cost 4.4 4.0 1.0 0.9 Expected Return on Plan Assets (6.5 ) (6.4 ) (1.9 ) (2.1 ) Amortization of Prior Service Credit — — (1.5 ) (1.5 ) Amortization of Net Actuarial Loss 1.2 1.8 0.5 0.2 Net Periodic Benefit Cost (Credit) $ 1.3 $ 1.7 $ (1.8 ) $ (2.2 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 6.5 $ 6.9 $ 0.5 $ 0.7 Interest Cost 13.1 12.0 3.0 2.8 Expected Return on Plan Assets (19.4 ) (19.2 ) (5.8 ) (6.4 ) Amortization of Prior Service Credit — — (4.4 ) (4.4 ) Amortization of Net Actuarial Loss 3.7 5.4 1.4 0.6 Net Periodic Benefit Cost (Credit) $ 3.9 $ 5.1 $ (5.3 ) $ (6.7 ) APCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 2.4 $ 2.4 $ 0.2 $ 0.3 Interest Cost 6.3 5.8 2.2 2.1 Expected Return on Plan Assets (9.4 ) (9.1 ) (3.7 ) (4.0 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 1.8 2.6 1.0 0.4 Net Periodic Benefit Cost (Credit) $ 1.1 $ 1.7 $ (2.8 ) $ (3.7 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 7.1 $ 7.0 $ 0.7 $ 0.8 Interest Cost 18.9 17.6 6.5 6.2 Expected Return on Plan Assets (28.1 ) (27.4 ) (11.0 ) (12.0 ) Amortization of Prior Service Credit — — (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 5.3 7.9 2.8 1.4 Net Periodic Benefit Cost (Credit) $ 3.2 $ 5.1 $ (8.5 ) $ (11.1 ) I&M Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 3.3 $ 3.4 $ 0.3 $ 0.4 Interest Cost 6.0 5.6 1.5 1.4 Expected Return on Plan Assets (9.1 ) (9.0 ) (2.8 ) (3.1 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 1.6 2.5 0.7 0.3 Net Periodic Benefit Cost (Credit) $ 1.8 $ 2.5 $ (2.7 ) $ (3.4 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 10.0 $ 10.2 $ 1.0 $ 1.2 Interest Cost 17.9 16.6 4.4 4.1 Expected Return on Plan Assets (27.5 ) (26.8 ) (8.5 ) (9.3 ) Amortization of Prior Service Credit — — (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 4.9 7.4 2.0 0.9 Net Periodic Benefit Cost (Credit) $ 5.3 $ 7.4 $ (8.2 ) $ (10.2 ) OPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 1.9 $ 2.0 $ 0.2 $ 0.2 Interest Cost 4.8 4.4 1.4 1.3 Expected Return on Plan Assets (7.3 ) (7.2 ) (2.7 ) (2.9 ) Amortization of Prior Service Credit — — (1.8 ) (1.7 ) Amortization of Net Actuarial Loss 1.3 2.0 0.6 0.3 Net Periodic Benefit Cost (Credit) $ 0.7 $ 1.2 $ (2.3 ) $ (2.8 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 5.9 $ 5.8 $ 0.6 $ 0.7 Interest Cost 14.3 13.3 4.1 3.9 Expected Return on Plan Assets (22.0 ) (21.6 ) (8.1 ) (8.8 ) Amortization of Prior Service Credit — — (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 4.0 6.0 1.9 0.8 Net Periodic Benefit Cost (Credit) $ 2.2 $ 3.5 $ (6.7 ) $ (8.6 ) PSO Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 1.6 $ 1.7 $ 0.2 $ 0.1 Interest Cost 2.6 2.5 0.7 0.6 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.3 ) (1.3 ) Amortization of Prior Service Credit — — (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 0.7 1.1 0.3 0.1 Net Periodic Benefit Cost (Credit) $ 0.9 $ 1.3 $ (1.2 ) $ (1.6 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 4.9 $ 5.3 $ 0.5 $ 0.5 Interest Cost 7.9 7.4 2.0 1.8 Expected Return on Plan Assets (12.2 ) (12.1 ) (3.9 ) (4.1 ) Amortization of Prior Service Credit — — (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 2.2 3.3 0.9 0.4 Net Periodic Benefit Cost (Credit) $ 2.8 $ 3.9 $ (3.7 ) $ (4.6 ) SWEPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 2.1 $ 2.4 $ 0.2 $ 0.2 Interest Cost 3.1 2.8 0.7 0.7 Expected Return on Plan Assets (4.4 ) (4.4 ) (1.5 ) (1.6 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 0.9 1.3 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.7 $ 2.1 $ (1.5 ) $ (1.8 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 6.4 $ 7.0 $ 0.6 $ 0.7 Interest Cost 9.3 8.5 2.3 2.1 Expected Return on Plan Assets (13.3 ) (13.1 ) (4.5 ) (4.8 ) Amortization of Prior Service Credit — — (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 2.6 3.8 1.1 0.5 Net Periodic Benefit Cost (Credit) $ 5.0 $ 6.2 $ (4.4 ) $ (5.4 )

Business Segments

Business Segments	9 Months Ended
	Sep. 30, 2019
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense, income tax expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2019 and 2018 and reportable segment balance sheet information as of September 30, 2019 and December 31, 2018 . Three Months Ended September 30, 2019 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,598.9 $ 1,147.3 $ 65.5 $ 501.2 $ 2.1 $ — $ 4,315.0 Other Operating Segments 46.6 39.3 207.5 32.5 22.3 (348.2 ) — Total Revenues $ 2,645.5 $ 1,186.6 $ 273.0 $ 533.7 $ 24.4 $ (348.2 ) $ 4,315.0 Net Income (Loss) $ 438.4 $ 133.7 $ 127.0 $ 88.7 $ (53.9 ) $ — $ 733.9 Three Months Ended September 30, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,610.2 $ 1,180.9 $ 51.9 $ 486.5 $ 3.6 $ — $ 4,333.1 Other Operating Segments 26.5 30.6 135.3 35.1 20.1 (247.6 ) — Total Revenues $ 2,636.7 $ 1,211.5 $ 187.2 $ 521.6 $ 23.7 $ (247.6 ) $ 4,333.1 Net Income (Loss) $ 345.6 $ 145.2 $ 74.2 $ 5.1 $ 9.6 $ — $ 579.7 Nine Months Ended September 30, 2019 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 7,087.6 $ 3,328.7 $ 196.5 $ 1,323.8 $ 8.8 $ — $ 11,945.4 Other Operating Segments 85.0 125.6 611.8 104.4 64.9 (991.7 ) — Total Revenues $ 7,172.6 $ 3,454.3 $ 808.3 $ 1,428.2 $ 73.7 $ (991.7 ) $ 11,945.4 Net Income (Loss) $ 920.8 $ 421.6 $ 407.6 $ 133.1 $ (116.0 ) $ — $ 1,767.1 Nine Months Ended September 30, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 7,332.4 $ 3,450.0 $ 196.5 $ 1,399.3 $ 16.4 $ — $ 12,394.6 Other Operating Segments 61.3 60.9 408.7 88.1 55.1 (674.1 ) — Total Revenues $ 7,393.7 $ 3,510.9 $ 605.2 $ 1,487.4 $ 71.5 $ (674.1 ) $ 12,394.6 Net Income (Loss) $ 856.3 $ 384.6 $ 280.9 $ 61.8 $ (17.1 ) $ — $ 1,566.5 September 30, 2019 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 46,739.8 $ 19,283.9 $ 9,700.4 $ 1,661.6 $ 421.7 $ (354.5 ) (b) $ 77,452.9 Accumulated Depreciation and Amortization 14,359.3 3,907.3 383.8 99.8 196.4 (186.4 ) (b) 18,760.2 Total Property Plant and Equipment - Net $ 32,380.5 $ 15,376.6 $ 9,316.6 $ 1,561.8 $ 225.3 $ (168.1 ) (b) $ 58,692.7 Total Assets $ 40,746.1 $ 17,967.6 $ 10,606.7 $ 3,315.9 $ 5,002.3 (c) $ (3,737.9 ) (b) (d) $ 73,900.7 Long-term Debt Due Within One Year: Nonaffiliated $ 687.4 $ 391.5 $ 249.0 $ — $ (0.2 ) (e) $ — $ 1,327.7 Long-term Debt: Affiliated 59.0 — — 32.2 — (91.2 ) — Nonaffiliated 12,161.1 5,868.9 3,426.9 (0.3 ) 3,096.9 — 24,553.5 Total Long-term Debt $ 12,907.5 $ 6,260.4 $ 3,675.9 $ 31.9 $ 3,096.7 (e) $ (91.2 ) $ 25,881.2 December 31, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 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 — 21,648.2 Total Long-term Debt $ 12,559.0 $ 5,597.9 $ 2,973.6 $ 32.0 $ 2,266.4 (e) $ (82.2 ) $ 23,346.7 (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 finance 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 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 three and nine months ended September 30, 2019 and 2018 and reportable segment balance sheet information as of September 30, 2019 and December 31, 2018 . Three Months Ended September 30, 2019 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 54.0 $ — $ — $ 54.0 Sales to AEP Affiliates 205.7 — — 205.7 Other Revenues — — — — Total Revenues $ 259.7 $ — $ — $ 259.7 Interest Income $ 0.4 $ 32.3 $ (31.9 ) (a) $ 0.8 Interest Expense 26.4 31.9 (31.9 ) (a) 26.4 Income Tax Expense 30.0 0.1 — 30.1 Net Income $ 107.3 $ 0.3 (b) $ — $ 107.6 Three Months Ended September 30, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 46.0 $ — $ — $ 46.0 Sales to AEP Affiliates 148.4 — — 148.4 Other Revenues — — — — Total Revenues $ 194.4 $ — $ — $ 194.4 Interest Income $ 0.2 $ 26.0 $ (25.7 ) (a) $ 0.5 Interest Expense 19.8 25.7 (25.7 ) (a) 19.8 Income Tax Expense 18.4 (0.8 ) — 17.6 Net Income $ 77.1 $ 1.0 (b) $ — $ 78.1 Nine Months Ended September 30, 2019 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 162.1 $ — $ — $ 162.1 Sales to AEP Affiliates 608.0 — — 608.0 Other Revenues — — — — Total Revenues $ 770.1 $ — $ — $ 770.1 Interest Income $ 0.8 $ 89.7 $ (88.4 ) (a) $ 2.1 Interest Expense 69.5 88.4 (88.4 ) (a) 69.5 Income Tax Expense 90.5 0.2 — 90.7 Net Income $ 347.1 $ 0.8 (b) $ — $ 347.9 Nine Months Ended September 30, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 132.3 $ — $ — $ 132.3 Sales to AEP Affiliates 453.8 — — 453.8 Other Revenues 0.1 — — 0.1 Total Revenues $ 586.2 $ — $ — $ 586.2 Interest Income $ 0.4 $ 76.2 $ (75.3 ) (a) $ 1.3 Interest Expense 60.7 75.3 (75.3 ) (a) 60.7 Income Tax Expense 63.7 — — 63.7 Net Income $ 243.6 $ 0.6 (b) $ — $ 244.2 September 30, 2019 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 9,267.4 $ — $ — $ 9,267.4 Accumulated Depreciation and Amortization 368.8 — — 368.8 Total Transmission Property – Net $ 8,898.6 $ — $ — $ 8,898.6 Notes Receivable - Affiliated $ — $ 3,511.9 $ (3,511.9 ) (c) $ — Total Assets $ 9,363.5 $ 3,589.0 (d) $ (3,599.8 ) (e) $ 9,352.7 Total Long-term Debt $ 3,550.0 $ 3,511.9 $ (3,550.0 ) (c) $ 3,511.9 December 31, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) 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 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Includes the elimination of AEPTCo Parent’s investments in State Transcos. (e) Primarily relates to the elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging

Derivatives and Hedging	9 Months Ended
	Sep. 30, 2019
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS 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 and credit 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 September 30, 2019 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 424.3 — 94.7 37.1 7.3 21.6 6.9 Natural Gas MMBtus 53.2 — — — — — 12.5 Heating Oil and Gasoline Gallons 8.4 1.8 1.6 0.8 2.0 0.8 0.9 Interest Rate USD $ 140.1 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 600.0 $ — $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — $ — 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. 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 $0 million and $18 million as of September 30, 2019 and December 31, 2018 , respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $21 million and $4 million as of September 30, 2019 and December 31, 2018 , 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 September 30, 2019 and December 31, 2018 . The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments September 30, 2019 Risk Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 337.0 $ 16.5 $ 1.9 $ 355.4 $ (168.7 ) $ 186.7 Long-term Risk Management Assets 319.0 10.0 25.3 354.3 (55.3 ) 299.0 Total Assets 656.0 26.5 27.2 709.7 (224.0 ) 485.7 Current Risk Management Liabilities 213.4 36.4 0.2 250.0 (174.7 ) 75.3 Long-term Risk Management Liabilities 281.7 87.4 — 369.1 (70.5 ) 298.6 Total Liabilities 495.1 123.8 0.2 619.1 (245.2 ) 373.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 160.9 $ (97.3 ) $ 27.0 $ 90.6 $ 21.2 $ 111.8 December 31, 2018 Risk Hedging Contracts Gross Amounts Gross Net Amounts of 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 AEP Texas Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — 0.1 0.1 Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Liabilities $ (0.4 ) $ — $ (0.4 ) December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 ) APCo Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 86.3 $ (29.8 ) $ 56.5 Long-term Risk Management Assets 4.1 (3.9 ) 0.2 Total Assets 90.4 (33.7 ) 56.7 Current Risk Management Liabilities 32.3 (31.2 ) 1.1 Long-term Risk Management Liabilities 4.4 (4.1 ) 0.3 Total Liabilities 36.7 (35.3 ) 1.4 Total MTM Derivative Contract Net Assets $ 53.7 $ 1.6 $ 55.3 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 I&M Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 30.5 $ (20.0 ) $ 10.5 Long-term Risk Management Assets 2.7 (2.6 ) 0.1 Total Assets 33.2 (22.6 ) 10.6 Current Risk Management Liabilities 21.0 (20.8 ) 0.2 Long-term Risk Management Liabilities 2.7 (2.7 ) — Total Liabilities 23.7 (23.5 ) 0.2 Total MTM Derivative Contract Net Assets $ 9.5 $ 0.9 $ 10.4 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 OPCo Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.2 — 7.2 Long-term Risk Management Liabilities 105.7 — 105.7 Total Liabilities 112.9 — 112.9 Total MTM Derivative Contract Net Liabilities $ (112.9 ) $ — $ (112.9 ) December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 ) PSO Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 21.9 $ (0.2 ) $ 21.7 Long-term Risk Management Assets — — — Total Assets 21.9 (0.2 ) 21.7 Current Risk Management Liabilities 0.5 (0.2 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.2 ) 0.3 Total MTM Derivative Contract Net Assets $ 21.4 $ — $ 21.4 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 SWEPCo Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 9.8 $ (0.4 ) $ 9.4 Long-term Risk Management Assets — — — Total Assets 9.8 (0.4 ) 9.4 Current Risk Management Liabilities 2.1 (0.4 ) 1.7 Long-term Risk Management Liabilities 3.0 — 3.0 Total Liabilities 5.1 (0.4 ) 4.7 Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 (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 Three Months Ended September 30, 2019 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.5 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.0 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.2 0.2 — — — Purchased Electricity for Resale 0.4 — 0.3 — — — — Other Operation (0.1 ) — (0.1 ) (0.1 ) (0.1 ) (0.1 ) — Maintenance (0.2 ) — — (0.1 ) — — — Regulatory Assets (a) (4.8 ) (0.2 ) 0.2 — (2.6 ) (0.1 ) (1.6 ) Regulatory Liabilities (a) 26.3 — 10.0 3.2 — 4.3 4.5 Total Gain (Loss) on Risk Management Contracts $ 43.1 $ (0.2 ) $ 10.6 $ 3.2 $ (2.7 ) $ 4.1 $ 2.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Three Months Ended September 30, 2018 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (0.7 ) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 19.3 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (0.5 ) (0.1 ) — — — Purchased Electricity for Resale 0.3 — 0.3 — — — — Other Operation 0.5 0.1 0.1 0.1 0.1 0.1 0.1 Maintenance 0.6 0.1 0.1 0.1 0.1 0.1 0.1 Regulatory Assets (a) (14.0 ) — — (3.5 ) (9.3 ) (0.6 ) (0.6 ) Regulatory Liabilities (a) 33.8 — 24.0 — — 3.9 1.5 Total Gain (Loss) on Risk Management Contracts $ 39.8 $ 0.2 $ 24.0 $ (3.4 ) $ (9.1 ) $ 3.5 $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts Nine Months Ended September 30, 2019 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 1.0 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 27.2 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.2 0.5 — — 0.1 Purchased Electricity for Resale 1.6 — 1.4 0.1 — — — Other Operation (0.6 ) (0.1 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Maintenance (0.6 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) — (0.1 ) Regulatory Assets (a) (19.4 ) 0.3 0.4 0.2 (19.8 ) 0.9 (0.4 ) Regulatory Liabilities (a) 64.5 — (5.3 ) 17.2 — 26.6 22.9 Total Gain (Loss) on Risk Management Contracts $ 73.7 $ 0.1 $ (3.5 ) $ 17.8 $ (20.1 ) $ 27.4 $ 22.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Nine Months Ended September 30, 2018 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (9.4 ) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 31.7 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (1.3 ) (7.8 ) — — 0.1 Purchased Electricity for Resale 8.3 — 7.3 0.8 — — — Other Operation 1.3 0.3 0.2 0.2 0.3 0.2 0.2 Maintenance 1.5 0.3 0.3 0.2 0.3 0.2 0.2 Regulatory Assets (a) 29.2 — — (0.3 ) 31.8 (0.6 ) (1.7 ) Regulatory Liabilities (a) 206.2 — 127.3 11.7 0.6 34.8 7.6 Total Gain on Risk Management Contracts $ 268.8 $ 0.6 $ 133.8 $ 4.8 $ 33.0 $ 34.6 $ 6.4 (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 Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) September 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018 (in millions) Long-term Debt (a) $ (521.2 ) $ (478.3 ) $ (25.1 ) $ 17.4 (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: Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Gain (Loss) on Interest Rate Contracts: Gain (Loss) on Fair Value Hedging Instruments (a) $ 13.2 $ (6.3 ) $ 42.5 $ (28.1 ) Gain (Loss) on Fair Value Portion of Long-term Debt (a) (13.2 ) 6.3 (42.5 ) 28.1 (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 three and nine months ended September 30, 2019 and 2018 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2019 and 2018 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2019 AEP applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three and nine months ended September 30, 2018 AEP and SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. 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 September 30, 2019 December 31, 2018 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Gain (Loss) Net of Tax $ (82.2 ) $ (16.7 ) (a) $ (23.0 ) $ (12.6 ) Portion Expected to be Reclassed to Net Income During the Next Twelve Months (24.2 ) (3.7 ) 10.4 (1.1 ) (a) Includes $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information. As of September 30, 2019 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months and 135 months for commodity and interest rate hedges, respectively. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2019 December 31, 2018 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) AEP Texas $ (3.6 ) $ (1.1 ) $ (4.4 ) $ (1.1 ) APCo 1.1 0.9 1.8 0.9 I&M (10.3 ) (1.6 ) (11.5 ) (1.6 ) OPCo — — 1.0 1.0 PSO 1.4 1.0 2.1 1.0 SWEPCo (2.2 ) (1.5 ) (3.3 ) (1.5 ) 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 September 30, 2019 and December 31, 2018 , respectively. 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: September 30, 2019 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 $ 261.0 $ 3.4 $ 230.7 APCo 3.9 — 0.2 I&M 2.3 — 0.1 SWEPCo 4.7 — 2.8 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

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2019
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. 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 fair value of AEP’s Equity Units (Level 1) are valued based on publicly traded securities issued by AEP. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2019 December 31, 2018 Company Book Value Fair Value Book Value Fair Value (in millions) AEP (a) $ 25,881.2 $ 29,729.1 $ 23,346.7 $ 24,093.9 AEP Texas 4,146.5 4,631.5 3,881.3 3,964.6 AEPTCo 3,511.9 3,984.9 2,823.0 2,782.4 APCo 4,362.9 5,370.2 4,062.6 4,473.3 I&M 3,031.5 3,497.3 3,035.4 3,070.2 OPCo 2,113.9 2,618.5 1,716.6 1,919.7 PSO 1,386.4 1,632.9 1,287.0 1,361.9 SWEPCo 2,656.9 2,983.0 2,713.4 2,670.2 (a) The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $887 million as of September 30, 2019 . See “Equity Units” section of Note 13 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2019 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 160.1 $ — $ — $ 160.1 Fixed Income Securities – Mutual Funds (b) 133.4 — (0.2 ) 133.2 Equity Securities – Mutual Funds 28.5 17.6 — 46.1 Total Other Temporary Investments $ 322.0 $ 17.6 $ (0.2 ) $ 339.4 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Proceeds from Investment Sales $ 2.8 $ — $ 2.8 $ — Purchases of Investments 26.9 0.8 35.8 2.2 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2018 , see Note 3 - Comprehensive Income. Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (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. The following is a summary of nuclear trust fund investments: September 30, 2019 December 31, 2018 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 17.4 $ — $ — $ 22.5 $ — $ — Fixed Income Securities: United States Government 1,047.4 67.8 (5.8 ) 996.1 26.7 (7.1 ) Corporate Debt 68.6 6.1 (1.7 ) 52.4 1.1 (1.9 ) State and Local Government 7.5 0.7 (0.2 ) 8.6 0.6 (0.2 ) Subtotal Fixed Income Securities 1,123.5 74.6 (7.7 ) 1,057.1 28.4 (9.2 ) Equity Securities - Domestic (a) 1,694.3 1,037.7 — 1,395.3 766.3 — Spent Nuclear Fuel and Decommissioning Trusts $ 2,835.2 $ 1,112.3 $ (7.7 ) $ 2,474.9 $ 794.7 $ (9.2 ) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $1 billion and $784 million and unrealized losses of $9 million and $18 million as of September 30, 2019 and December 31, 2018 , respectively. 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: Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Proceeds from Investment Sales $ 671.9 $ 513.1 $ 871.4 $ 1,550.9 Purchases of Investments 689.1 521.2 915.7 1,589.0 Gross Realized Gains on Investment Sales 10.9 3.9 26.6 27.7 Gross Realized Losses on Investment Sales 7.1 3.5 15.1 22.2 The base cost of fixed income securities was $1 billion and $1 billion as of September 30, 2019 and December 31, 2018 , respectively. The base cost of equity securities was $657 million and $629 million as of September 30, 2019 and December 31, 2018 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2019 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 334.9 After 1 year through 5 years 390.9 After 5 years through 10 years 199.2 After 10 years 198.5 Total $ 1,123.5 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 152.9 $ — $ — $ 7.2 $ 160.1 Fixed Income Securities – Mutual Funds 133.2 — — — 133.2 Equity Securities – Mutual Funds (b) 46.1 — — — 46.1 Total Other Temporary Investments 332.2 — — 7.2 339.4 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.6 228.2 407.7 (195.3 ) 446.2 Cash Flow Hedges: Commodity Hedges (c) — 17.6 2.9 (8.2 ) 12.3 Interest Rate Hedges — 1.9 — — 1.9 Fair Value Hedges — 25.3 — — 25.3 Total Risk Management Assets 5.6 273.0 410.6 (203.5 ) 485.7 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 8.0 17.4 Fixed Income Securities: United States Government — 1,047.4 — — 1,047.4 Corporate Debt — 68.6 — — 68.6 State and Local Government — 7.5 — — 7.5 Subtotal Fixed Income Securities — 1,123.5 — — 1,123.5 Equity Securities – Domestic (b) 1,694.3 — — — 1,694.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,703.7 1,123.5 — 8.0 2,835.2 Total Assets $ 2,041.5 $ 1,396.5 $ 410.6 $ (188.3 ) $ 3,660.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.1 $ 243.9 $ 231.6 $ (216.5 ) $ 264.1 Cash Flow Hedges: Commodity Hedges (c) — 49.1 68.7 (8.2 ) 109.6 Fair Value Hedges — 0.2 — — 0.2 Total Risk Management Liabilities $ 5.1 $ 293.2 $ 300.3 $ (224.7 ) $ 373.9 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) (f) 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) (f) $ 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 Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 114.3 $ — $ — $ — $ 114.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 0.4 $ — $ — $ 0.4 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 17.1 $ — $ — $ — $ 17.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 31.4 57.3 (32.0 ) 56.7 Total Assets $ 17.1 $ 31.4 $ 57.3 $ (32.0 ) $ 73.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 33.2 $ 1.8 $ (33.6 ) $ 1.4 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 21.9 $ 10.2 $ (21.5 ) $ 10.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 8.0 17.4 Fixed Income Securities: United States Government — 1,047.4 — — 1,047.4 Corporate Debt — 68.6 — — 68.6 State and Local Government — 7.5 — — 7.5 Subtotal Fixed Income Securities — 1,123.5 — — 1,123.5 Equity Securities - Domestic (b) 1,694.3 — — — 1,694.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,703.7 1,123.5 — 8.0 2,835.2 Total Assets $ 1,703.7 $ 1,145.4 $ 10.2 $ (13.5 ) $ 2,845.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.3 $ 1.3 $ (22.4 ) $ 0.2 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Liabilities: (in millions) Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 112.5 $ — $ 112.9 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 22.0 $ (0.3 ) $ 21.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.4 $ (0.3 ) $ 0.3 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.8 $ (0.4 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 4.9 $ (0.4 ) $ 4.7 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 (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 September 30, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2019, $(8) million in periods 2020-2022 and $(1) million in periods 2025-2032; Level 3 matures $40 million in 2019, $114 million in periods 2020-2022, $26 million in periods 2023-2024 and $(4) 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2019 and 2018 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2019 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2019 $ 112.7 $ 68.5 $ 12.3 $ (111.5 ) $ 27.8 $ 8.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 30.2 13.8 3.1 — 4.1 3.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 22.1 — — — — — Settlements (67.4 ) (28.1 ) (7.2 ) 1.1 (11.2 ) (6.7 ) Transfers into Level 3 (c) (d) 3.5 — — — — — Transfers out of Level 3 (d) 6.6 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) (0.3 ) 1.3 0.7 (2.1 ) 0.9 (0.5 ) Balance as of September 30, 2019 $ 110.3 $ 55.5 $ 8.9 $ (112.5 ) $ 21.6 $ 4.9 Three Months Ended September 30, 2018 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2018 $ 172.3 $ 60.0 $ 13.2 $ (86.9 ) $ 24.3 $ 4.9 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 19.9 9.0 1.9 — 3.7 1.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 1.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 10.4 — — — — — Settlements (56.0 ) (19.8 ) (5.5 ) 0.6 (10.8 ) (2.7 ) Transfers into Level 3 (c) (d) 2.3 — — — — — Transfers out of Level 3 (d) (1.2 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 12.0 17.3 (0.2 ) (8.9 ) 0.4 (0.4 ) Balance as of September 30, 2018 $ 161.2 $ 66.5 $ 9.4 $ (95.2 ) $ 17.6 $ 3.5 Nine Months Ended September 30, 2019 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2018 $ 131.2 $ 57.8 $ 8.9 $ (99.4 ) $ 9.5 $ 2.3 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 14.6 (14.1 ) 4.6 (0.9 ) 13.5 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 32.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (42.8 ) — — — — — Settlements (114.6 ) (41.9 ) (12.6 ) 4.6 (23.0 ) (10.1 ) Transfers into Level 3 (c) (d) 0.4 — — — — — Transfers out of Level 3 (d) 1.4 (0.7 ) (0.4 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 87.2 54.4 8.4 (16.8 ) 21.6 6.7 Balance as of September 30, 2019 $ 110.3 $ 55.5 $ 8.9 $ (112.5 ) $ 21.6 $ 4.9 Nine Months Ended September 30, 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) (a) (b) 150.9 104.4 14.7 1.3 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 (a) 9.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 16.4 — — — — — Settlements (212.3 ) (128.3 ) (21.9 ) 3.0 (24.3 ) (1.3 ) Transfers into Level 3 (c) (d) 16.5 — — — — — Transfers out of Level 3 (d) (2.5 ) — (0.3 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 142.4 65.7 9.3 32.9 17.6 3.7 Balance as of September 30, 2018 $ 161.2 $ 66.5 $ 9.4 $ (95.2 ) $ 17.6 $ 3.5 (a) Included in revenues on the statements of income. (b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (c) Represents existing assets or liabilities that were previously categorized as Level 2. (d) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (e) 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: AEP Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 298.8 $ 286.8 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 180.10 $ 31.34 Natural Gas Contracts — 4.5 Discounted Cash Flow Forward Market Price (b) 1.96 2.62 2.25 FTRs 111.8 9.0 Discounted Cash Flow Forward Market Price (a) (10.40 ) 11.65 0.54 Total $ 410.6 $ 300.3 December 31, 2018 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 APCo Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 3.6 $ 1.1 Discounted Cash Flow Forward Market Price $ 12.93 $ 59.25 $ 31.28 FTRs 53.7 0.7 Discounted Cash Flow Forward Market Price (0.91 ) 10.14 1.63 Total $ 57.3 $ 1.8 December 31, 2018 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 I&M Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.2 $ 0.7 Discounted Cash Flow Forward Market Price $ 12.93 $ 59.25 $ 31.28 FTRs 8.0 0.6 Discounted Cash Flow Forward Market Price (1.76 ) 7.26 0.87 Total $ 10.2 $ 1.3 December 31, 2018 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 OPCo Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ — $ 112.5 Discounted Cash Flow Forward Market Price $ 27.47 $ 65.81 $ 40.30 December 31, 2018 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 PSO Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 22.0 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.87 ) $ 0.93 $ (2.19 ) December 31, 2018 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 ) SWEPCo Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 4.5 Discounted Cash Flow Forward Market Price (b) $ 1.96 $ 2.62 $ 2.25 FTRs 9.8 0.4 Discounted Cash Flow Forward Market Price (a) (6.87 ) 0.93 (2.19 ) Total $ 9.8 $ 4.9 December 31, 2018 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 (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 September 30, 2019 and December 31, 2018 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Hig

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2019
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. 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 related to regulatory filings in these jurisdictions. 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 Case Pending Case Pending I&M (Michigan) Order Issued Case Pending Case Pending SWEPCo (Louisiana) Case Pending – Rates Implemented (b) Case Pending – Rates Implemented (b) Case Pending – Rates Implemented (b) SWEPCo (Texas) Order Issued 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 addressed in a current pending case. (b) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval. Effective Tax Rates (ETR) The Registrants’ interim ETR reflect the estimated annual ETR for 2019 and 2018 , adjusted for tax expense associated with certain discrete items. The interim ETR differ from the federal statutory tax rate of 21% primarily due to increased amortization of Excess ADIT, tax credits and other book/tax differences which are accounted for on a flow-through basis. The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods. Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR ratably during each interim period due to the variability of pretax book income between interim periods and the application of an annual estimated ETR. The ETR for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2019 2018 2019 2018 AEP 5.2 % (16.2 )% 1.7 % 5.6 % AEP Texas 15.1 % 12.6 % (25.3 )% 14.9 % AEPTCo 21.9 % 18.4 % 20.7 % 20.7 % APCo (3.9 )% (962.2 )% (19.1 )% (13.8 )% I&M (2.7 )% 15.9 % (2.1 )% 10.4 % OPCo 13.9 % (46.4 )% 14.2 % 4.6 % PSO 6.4 % 5.6 % 4.6 % 8.7 % SWEPCo (0.6 )% 9.8 % — % 11.4 % AEP Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The increase in the ETR was primarily due to $71 million of decreased amortization of Excess ADIT not subject to normalization requirements and $14 million of increased state tax expense which impacted the ETR by 19.1% and 1.3% , respectively. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The decrease in the ETR was primarily due to $93 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4.5)% . AEP Texas Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The increase in ETR was primarily due to significantly higher pretax book income which reduced the impact that favorable tax deductions had on the ETR. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The decrease in the ETR was primarily due to $59 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (38.9)% . Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements of the Stipulation and Settlement agreement approved by the PUCT in August 2018 and the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. AEPTCo Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The increase in the ETR was primarily due to $3 million of increased state tax expense and $2 million of decreased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by 1.3% and 1% , respectively. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The ETR remained consistent for the nine months ended September 30, 2019 and 2018. APCo Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The increase in the ETR was primarily due to $56 million of decreased amortization of Excess ADIT not subject to normalization requirements and $6 million of increased state tax expense which impacted the ETR by 947.3% and 34.8% , respectively. Amortization of Excess ADIT not subject to normalization requirements primarily decreased from the prior year due to the discrete impact of the West Virginia Tax Reform order which enabled APCo to utilize $73 million of Excess ADIT not subject to normalization requirements to offset certain regulatory asset balances in the third quarter of 2018. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The decrease in the ETR was primarily due to $9 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4.6)% . Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the October 2018 and March 2019 Virginia SCC Tax Reform orders as well as the August 2018 and February 2019 WVPSC orders. I&M Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The decrease in the ETR was primarily due to $10 million of increased amortization of Excess ADIT, $3 million of increased favorable book/tax differences accounted for on a flow-through basis, $2 million of decreased state income tax expense and $1 million of increased parent company loss benefit which impacted the ETR by (11.3)% , (3.2)% , (1.8)% and (1.6)% respectively. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The decrease in the ETR was primarily due to $16 million of increased amortization of Excess ADIT not subject to normalization requirements and $12 million of increased favorable book/tax differences accounted for on a flow-through basis which impacted the ETR by (6.9)% and (4.8)% , respectively. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the Tax Reform elements of the 2017 Indiana Base Rate Case approved by the IURC in May 2018. OPCo Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The increase in the ETR was primarily due to $35 million of decreased amortization of Excess ADIT not subject to normalization requirements and $1 million of decreased parent company loss benefit which impacted the ETR by 60% and 2% , respectively. Amortization of Excess ADIT not subject to amortization requirements decreased from the prior year primarily due to the discrete impact of the Ohio Tax Reform order which enabled OPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances in the third quarter of 2018. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The increase in the ETR was primarily due to $24 million of decreased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by 10.8% . Amortization of Excess ADIT not subject to amortization requirements decreased from the prior year primarily due to the discrete impact of the Ohio Tax Reform order which enabled OPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances in the third quarter of 2018. PSO Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The ETR remained comparable for the three months ended September 30, 2019 and 2018. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The decrease in the ETR was primarily due to $15 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (6.8)% . Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the August 2018 OCC Tax Reform order as well as Tax Reform elements of the 2018 Oklahoma Base Rate Case approved by the OCC in March 2019. SWEPCo Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018 The decrease in the ETR was primarily due to $11 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (9.7)% . Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements incorporated in the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018. Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 The decrease in the ETR was primarily due to $15 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (10.4)% . Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements incorporated in the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination by the IRS for all years through 2013. During the IRS examination of years 2011 through 2014, the statute of limitations for these years was extended to coincide with the examination of 2015. During the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 and 2015 federal returns. Due to the amendment of these federal returns, the 2014 and 2015 years will remain open for possible IRS examination for only the items that were amended on the 2014 and 2015 federal return s. The IRS examination of 2016 began in October 2018 and concluded in March 2019. State Tax Legislation (Applies to AEP, AEPTCo, I&M and OPCo) In April 2018, the Kentucky legislature enacted House Bill (H.B.) 487. H.B. 487 adopts mandatory unitary combined reporting for state corporate income tax purposes applicable for taxable years beginning on or after January 1, 2019. H.B. 487 also adopts the 80% federal net operating loss (NOL) limitation under Internal Revenue Code Sec. 172(a) for NOLs generated after January 1, 2018 and the federal unlimited carryforward period for unused NOLs generated after January 1, 2018. In addition, H.B. 366 was also enacted in April 2018, which among other things, replaces the graduated corporate tax rate structure with a flat 5% tax rate for business income and adopts a single-sales factor apportionment formula for apportioning a corporation’s business income to Kentucky. In the second quarter of 2018, AEP recorded an $18 million benefit to Income Tax Expense (Benefit) as a result of remeasuring Kentucky deferred taxes under a unitary filing group. The enacted legislation did not materially impact AEPTCo’s, I&M’s or OPCo’s net income.

Leases

Leases	9 Months Ended
	Sep. 30, 2019
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. As of the adoption date of ASU 2016-02, management elected not to separate non-lease components from associated lease components in accordance with the accounting guidance for “Leases.” Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option. Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk free rate and a secured credit spread relative to the lessee on a matched maturity basis. Lease rentals for both operating and finance leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs were as follows: Three Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 64.4 $ 4.0 $ 0.6 $ 4.9 $ 23.7 $ 4.9 $ 1.5 $ 1.8 Finance Lease Cost: Amortization of Right-of-Use Assets 16.5 1.5 0.1 2.0 1.6 1.1 0.8 2.8 Interest on Lease Liabilities 4.1 0.3 — 0.8 0.8 0.2 0.1 0.7 Total Lease Rental Costs (a) $ 85.0 $ 5.8 $ 0.7 $ 7.7 $ 26.1 $ 6.2 $ 2.4 $ 5.3 Nine Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 200.3 $ 12.2 $ 1.7 $ 14.5 $ 70.0 $ 13.8 $ 5.0 $ 5.7 Finance Lease Cost: Amortization of Right-of-Use Assets 45.0 3.8 0.1 5.0 4.2 2.6 2.2 8.2 Interest on Lease Liabilities 12.2 1.0 — 2.2 2.3 0.5 0.4 2.2 Total Lease Rental Costs (a) $ 257.5 $ 17.0 $ 1.8 $ 21.7 $ 76.5 $ 16.9 $ 7.6 $ 16.1 (a) Excludes variable and short-term lease costs, which were immaterial for the three and nine months ended September 30, 2019 . Supplemental information related to leases are shown in the tables below: September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo Weighted-Average Remaining Lease Term (years): Operating Leases 5.31 7.05 2.43 6.25 4.05 8.10 7.06 6.63 Finance Leases 5.87 6.86 0.58 6.33 6.72 6.58 6.24 5.34 Weighted-Average Discount Rate: Operating Leases 3.61 % 3.79 % 3.13 % 3.67 % 3.45 % 3.79 % 3.68 % 3.80 % Finance Leases 6.02 % 4.71 % 9.33 % 8.19 % 8.61 % 4.66 % 4.73 % 5.03 % Nine Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows Used for Operating Leases $ 163.6 $ 11.4 $ 1.7 $ 14.1 $ 52.5 $ 13.8 $ 4.9 $ 5.3 Operating Cash Flows Used for Finance Leases 11.0 1.0 — 2.2 2.2 0.5 0.4 1.1 Financing Cash Flows Used for Finance Leases 44.5 3.8 — 5.0 4.0 2.6 2.2 8.1 Non-cash Acquisitions Under Operating Leases $ 108.9 $ 12.7 $ — $ 8.6 $ 16.6 $ 34.6 $ 7.3 $ 10.6 The following tables show the property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months. September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Finance Leases: Generation $ 134.9 $ — $ — $ 41.3 $ 28.5 $ — $ 2.6 $ 34.2 Other Property, Plant and Equipment 335.9 41.9 0.2 18.4 37.1 24.7 20.7 50.0 Total Property, Plant and Equipment 470.8 41.9 0.2 59.7 65.6 24.7 23.3 84.2 Accumulated Amortization 162.7 10.9 0.2 17.8 22.8 6.6 9.1 26.2 Net Property, Plant and Equipment Under Finance Leases $ 308.1 $ 31.0 $ — $ 41.9 $ 42.8 $ 18.1 $ 14.2 $ 58.0 Obligations Under Finance Leases: Noncurrent Liability $ 254.0 $ 25.8 $ — $ 35.2 $ 37.1 $ 14.5 $ 11.0 $ 50.5 Liability Due Within One Year 61.4 5.2 — 6.7 6.0 3.6 3.2 11.2 Total Obligations Under Finance Leases $ 315.4 $ 31.0 $ — $ 41.9 $ 43.1 $ 18.1 $ 14.2 $ 61.7 September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Assets $ 990.0 $ 82.0 $ 4.6 $ 79.4 $ 295.3 $ 88.2 $ 37.1 $ 40.8 Obligations Under Operating Leases: Noncurrent Liability $ 801.1 $ 71.1 $ 2.2 $ 64.8 $ 234.0 $ 75.9 $ 31.2 $ 32.5 Liability Due Within One Year 228.8 11.7 2.3 15.3 82.0 12.8 6.0 5.9 Total Obligations Under Operating Leases $ 1,029.9 $ 82.8 $ 4.5 $ 80.1 $ 316.0 $ 88.7 $ 37.2 $ 38.4 Future minimum lease payments as of September 30, 2019 are presented on a rolling 12-month basis as shown in the tables below: Finance Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year 1 $ 76.8 $ 6.6 $ — $ 9.6 $ 9.0 $ 4.3 $ 3.8 $ 13.0 Year 2 67.0 6.1 — 8.8 8.2 3.9 3.1 11.6 Year 3 58.0 5.3 — 8.1 7.6 3.2 2.3 10.6 Year 4 49.0 4.9 — 7.5 7.1 2.5 2.1 9.5 Year 5 50.0 4.1 — 7.0 6.7 2.1 1.7 14.8 Later Years 76.1 9.8 — 11.3 20.9 5.3 3.7 7.5 Total Future Minimum Lease Payments 376.9 36.8 — 52.3 59.5 21.3 16.7 67.0 Less Imputed Interest 61.5 5.8 — 10.4 16.4 3.2 2.5 5.3 Estimated Present Value of Future Minimum Lease Payments $ 315.4 $ 31.0 $ — $ 41.9 $ 43.1 $ 18.1 $ 14.2 $ 61.7 Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year 1 $ 267.5 $ 15.7 $ 2.4 $ 18.4 $ 92.2 $ 16.6 $ 7.4 $ 8.4 Year 2 252.4 15.2 1.5 16.4 88.4 13.9 6.6 8.2 Year 3 239.9 14.1 0.7 14.7 86.3 13.3 6.0 7.5 Year 4 154.2 13.0 0.3 12.5 48.0 12.4 5.5 7.2 Year 5 63.6 11.4 — 9.8 7.3 10.8 5.0 5.0 Later Years 184.1 27.8 — 20.1 22.0 38.3 12.7 12.4 Total Future Minimum Lease Payments 1,161.7 97.2 4.9 91.9 344.2 105.3 43.2 48.7 Less Imputed Interest 131.8 14.4 0.4 11.8 28.2 16.6 6.0 10.3 Estimated Present Value of Future Minimum Lease Payments $ 1,029.9 $ 82.8 $ 4.5 $ 80.1 $ 316.0 $ 88.7 $ 37.2 $ 38.4 Future minimum lease payments consisted of the following as of December 31, 2018 : Finance 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 Imputed Interest 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 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 September 30, 2019 , 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 $ 46.6 AEP Texas 11.2 APCo 6.3 I&M 4.0 OPCo 7.4 PSO 4.3 SWEPCo 4.7 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. In the first quarter of 2019, in accordance with ASU 2016-02, the $37 million unamortized gain ( $15 million related to I&M) associated with the sale-and-leaseback of the Plant was recognized as an adjustment to equity. The adjustment to equity was then reclassified to regulatory liabilities in accordance with accounting guidance for “Regulated Operations” as AEGCo and I&M will continue to provide the benefit of the unamortized gain to customers in future periods. The Owner Trustee owns the Plant and leases equal portions 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 and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value. The option to renew was not included in the measurement of the lease obligation as of September 30, 2019 as the execution of the option was not reasonably certain. 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 September 30, 2019 were as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2019 $ 74.2 $ 37.1 2020 147.8 73.9 2021 147.8 73.9 2022 147.2 73.6 Total Future Minimum Lease Payments $ 517.0 $ 258.5 (a) AEP’s future minimum lease payments include equal shares from AEGCo and I&M. 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 September 30, 2019 , the maximum potential amount of future payments required under the guaranteed leases was $56 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 September 30, 2019 , AEP’s boat and barge lease guarantee liability was $4 million , of which $1 million was recorded in Other Current Liabilities and $3 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. (Moody’s) also downgraded their rating and set their outlook to negative. Moody’s further downgraded their rating in April 2019 and maintained a negative outlook. 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. Lessor Activity The Registrants’ lessor activity was immaterial as of and for the three and nine months ended September 30, 2019 .

Financing Activities

Financing Activities	9 Months Ended
	Sep. 30, 2019
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding, net of issuance costs and premiums or discounts: Type of Debt September 30, 2019 December 31, 2018 (in millions) Senior Unsecured Notes $ 20,829.2 $ 18,903.3 Pollution Control Bonds 1,516.5 1,643.8 Notes Payable 189.1 204.7 Securitization Bonds 1,059.4 1,111.4 Spent Nuclear Fuel Obligation (a) 278.5 273.6 Junior Subordinated Notes (b) 786.8 — Other Long-term Debt 1,221.7 1,209.9 Total Long-term Debt Outstanding 25,881.2 23,346.7 Long-term Debt Due Within One Year 1,327.7 1,698.5 Long-term Debt $ 24,553.5 $ 21,648.2 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $322 million and $317 million as of September 30, 2019 and December 31, 2018 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) See “Equity Units” section below for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2019 are shown in the following tables: Principal Interest Company Type of Debt Amount (a) Rate Due Date Issuances: (in millions) (%) AEP Junior Subordinated Notes (b) $ 805.0 3.40 2024 AEP Texas Securitization Bonds 117.6 2.06 2025 AEP Texas Securitization Bonds 117.6 2.29 2029 AEP Texas Pollution Control Bonds 100.6 2.60 2029 AEP Texas Senior Unsecured Notes 300.0 4.15 2049 AEPTCo Senior Unsecured Notes 350.0 3.80 2049 AEPTCo Senior Unsecured Notes 350.0 3.15 2049 APCo Pollution Control Bonds 86.0 2.55 2024 APCo Senior Unsecured Notes 400.0 4.50 2049 I&M Notes Payable 62.8 Variable 2023 OPCo Senior Unsecured Notes 450.0 4.00 2049 PSO Senior Unsecured Notes 100.0 3.91 2029 PSO Senior Unsecured Notes 150.0 4.11 2034 PSO Senior Unsecured Notes 100.0 4.50 2049 Non-Registrant: AEGCo Pollution Control Bonds 45.0 1.35 2022 Transource Energy Other Long-term Debt 14.4 Variable 2020 Total Issuances $ 3,549.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. (b) See “Equity Units” section below for additional information. Principal Interest Company Type of Debt Amount Paid Rate Due Date Retirements and Principal Payments: (in millions) (%) AEP Texas Senior Unsecured Notes $ 50.0 2.61 2019 AEP Texas Securitization Bonds 28.2 1.98 2020 AEP Texas Securitization Bonds 188.0 5.31 2020 AEP Texas Pollution Control Bonds 100.6 6.30 2029 APCo Pollution Control Bonds 86.0 1.90 2019 APCo Pollution Control Bonds 70.0 3.25 2019 APCo Securitization Bonds 24.4 2.01 2023 I&M Notes Payable 2.7 Variable 2019 I&M Notes Payable 4.3 Variable 2019 I&M Notes Payable 13.7 Variable 2020 I&M Notes Payable 17.9 Variable 2021 I&M Notes Payable 11.3 Variable 2022 I&M Notes Payable 16.0 Variable 2022 I&M Notes Payable 6.4 Variable 2023 I&M Other Long-term Debt 1.3 6.00 2025 OPCo Securitization Bonds 47.9 2.05 2019 OPCo Other Long-term Debt 0.1 1.15 2028 PSO Senior Unsecured Notes 250.0 5.15 2019 PSO Other Long-term Debt 0.4 3.00 2027 SWEPCo Pollution Control Bonds 53.5 1.60 2019 SWEPCo Other Long-term Debt 1.5 4.68 2028 SWEPCo Notes Payable 3.2 4.58 2032 Non-Registrant: AEGCo Pollution Control Bonds 45.0 Variable 2019 AEP Energy Notes Payable 0.1 5.75 2019 Transource Energy Other Long-term Debt 1.0 Variable 2020 Total Retirements and Principal Payments $ 1,023.5 As of September 30, 2019 , trustees held, on behalf of AEP, $574 million of their reacquired Pollution Control Bonds. Of this total, $345 million relates to OPCo. Long-term Debt Subsequent Events In October 2019, AEP remarketed $240 million of Pollution Control Bonds that were held in trust. In October 2019, I&M retired $4 million of Notes Payable related to DCC Fuel. In October 2019, I&M retired $25 million of variable rate Pollution Control Bonds. Equity Units (Applies to AEP) In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million . Net proceeds from the issuance were approximately $785 million . The proceeds were used to support AEP’s overall capital expenditure plans including the recent acquisition of Sempra Renewables LLC. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settles after three years in 2022 . The notes are expected to be remarketed in 2022, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125% , which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725% . Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment): • If the AEP common stock market price is equal to or greater than $99.58 : 0.5021 shares per contract. • If the AEP common stock market price is less than $99.58 but greater than $82.98 : a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50. • If the AEP common stock market price is less than or equal to $82.98 : 0.6026 shares per contract. A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes. At the time of issuance, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2022. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment). 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 0.1% of consolidated tangible net assets as of September 30, 2019 . The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. However, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain 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 Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; 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 its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2019 and December 31, 2018 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the nine months ended September 30, 2019 are described in the following table: 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 September 30, 2019 Limit (in millions) AEP Texas $ 390.7 $ — $ 261.8 $ — $ (74.8 ) $ 500.0 AEPTCo 374.9 244.4 179.8 40.2 236.6 795.0 (a) APCo 225.4 232.2 90.4 61.8 (17.7 ) 600.0 I&M 120.4 66.0 53.1 17.2 (89.2 ) 500.0 OPCo 291.2 178.6 163.5 50.1 (17.6 ) 500.0 PSO 140.5 215.6 63.9 84.1 95.1 300.0 SWEPCo 105.1 81.4 57.8 11.2 6.4 350.0 (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 table 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 September 30, 2019 and December 31, 2018 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2019 is described in the following table: Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool September 30, 2019 (in millions) AEP Texas $ 8.0 $ 7.7 $ 7.7 SWEPCo 2.1 2.0 2.1 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of September 30, 2019 and December 31, 2018 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 2019 are described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2019 September 30, 2019 Borrowing Limit (in millions) $ 1.3 $ 117.6 $ 1.3 $ 63.4 $ 1.3 $ 30.8 $ 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: Nine Months Ended September 30, 2019 2018 Maximum Interest Rate 3.43 % 2.52 % Minimum Interest Rate 1.83 % 1.81 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Average Interest Rate for Funds Borrowed from the Utility Money Pool Loaned to the Utility Money Pool for Nine Months Ended September 30, for Nine Months Ended September 30, Company 2019 2018 2019 2018 AEP Texas 2.71 % 2.25 % — % 2.29 % AEPTCo 2.72 % 2.26 % 2.57 % 2.04 % APCo 2.82 % 2.22 % 2.73 % 2.19 % I&M 2.56 % 2.16 % 2.73 % 2.06 % OPCo 2.80 % 2.18 % 2.68 % 2.47 % PSO 2.85 % 2.25 % 2.48 % 1.86 % SWEPCo 2.74 % 2.31 % 2.47 % 1.87 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table: Nine Months Ended September 30, 2019 Nine Months Ended September 30, 2018 Maximum Minimum Average Maximum Minimum 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 Loaned to Loaned to Loaned to Loaned to Loaned to 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 3.02 % 2.36 % 2.70 % 2.52 % 1.83 % 2.26 % SWEPCo 3.02 % 2.36 % 2.70 % 2.52 % 1.83 % 2.26 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2019 3.02 % 2.36 % 3.02 % 2.36 % 2.70 % 2.70 % 2018 2.52 % 1.76 % 2.52 % 1.76 % 2.26 % 2.27 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2019 December 31, 2018 Outstanding Interest Outstanding Interest Type of Debt Amount Rate (a) Amount Rate (a) (dollars in millions) Securitized Debt for Receivables (b) $ 750.0 2.56 % $ 750.0 2.16 % Commercial Paper 1,760.0 2.36 % 1,160.0 2.96 % Total Short-term Debt $ 2,510.0 $ 1,910.0 (a) Weighted-average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement that provides a commitment of $750 million from bank conduits to purchase receivables and expires in July 2021. 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. Accounts receivable information for AEP Credit was as follows: Three Months Ended Nine Months Ended 2019 2018 2019 2018 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 2.37 % 2.27 % 2.56 % 2.06 % Net Uncollectible Accounts Receivable Written-Off $ 8.8 $ 9.6 $ 19.8 $ 19.0 September 30, 2019 December 31, 2018 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 923.3 $ 972.5 Short-term – Securitized Debt of Receivables 750.0 750.0 Delinquent Securitized Accounts Receivable 43.9 50.3 Bad Debt Reserves Related to Securitization 32.3 27.5 Unbilled Receivables Related to Securitization 216.2 281.4 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 AEP Texas and AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were: Company September 30, 2019 December 31, 2018 (in millions) APCo $ 95.4 $ 133.3 I&M 156.2 152.9 OPCo 337.5 395.2 PSO 149.4 109.7 SWEPCo 168.6 150.3 The fees paid to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2019 2018 2019 2018 (in millions) APCo $ 1.2 $ 1.8 $ 5.8 $ 5.1 I&M 2.4 2.5 8.4 6.8 OPCo 6.4 7.2 22.1 18.8 PSO 2.0 2.3 6.2 6.0 SWEPCo 1.9 2.6 7.9 6.6 The proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2019 2018 2019 2018 (in millions) APCo $ 303.3 $ 334.1 $ 978.5 $ 1,079.2 I&M 485.3 498.4 1,378.9 1,401.7 OPCo 602.6 695.2 1,746.1 2,046.9 PSO 451.5 454.9 1,118.7 1,171.2 SWEPCo 480.7 512.6 1,247.0 1,364.6

Variable Interest Entities and

Variable Interest Entities and Equity Method Investments	9 Months Ended
	Sep. 30, 2019
Variable Interest Entities	VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS The disclosures in this note apply to AEP only 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 holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting. The Variable Interest Entities note within the 2018 Annual Report should be read in conjunction with this report as this note only includes significant changes to AEP’s VIEs and equity method investments during 2019. Consolidated Variable Interests Entities Restoration Funding (Applies to AEP and AEP Texas) Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas’ distribution system primarily due to damage caused by Hurricane Harvey. See “Texas Storm Cost Securitization” section of Note 4 for additional information. Management has concluded that AEP Texas is the primary beneficiary of Restoration 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 Restoration Funding. The securitized bonds totaled $235 million as of September 30, 2019 and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Restoration Funding has securitized assets of $235 million as of September 30, 2019 which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration 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 assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Fundings’ securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Restoration Fundings’ assets and liabilities on the balance sheets. Apple Blossom Wind Holdings LLC and Black Oak Getty Wind Holdings LLC In April 2019, AEP acquired an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (the Project Entities) as part of the purchase of Sempra Renewables LLC. Both of the Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management has concluded that the Project Entities are VIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact the Project Entities’ economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. As the primary beneficiary of the Project Entities, AEP consolidates the Project Entities into its financial statements. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheets. The nonaffiliated interests in the Project Entities is presented in Noncontrolling Interests on the balance sheets. As of September 30, 2019 , AEP recorded $129 million of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets. The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the three and nine months ended September 30, 2019 , the HLBV method resulted in $0 and a loss of $4 million , respectively, allocated to Noncontrolling Interests. Santa Rita East In July 2019, AEP acquired a 75% interest in Santa Rita East Wind Energy Holdings, LLC and its wholly-owned subsidiary, Santa Rita East Wind Energy, LLC (collectively, Santa Rita East). Santa Rita East is a partnership whose sole purpose is to own and operate a new 302.4 MW wind generation facility in west Texas. Santa Rita East delivers energy and provides renewable energy credits through three long-term PPAs totaling 260 MWs. The remaining 42.4 MWs of energy are sold at wholesale into ERCOT. Management has concluded that Santa Rita East is a VIE and that AEP is the primary beneficiary based on its power as managing member of the partnership to direct the activities that most significantly impact Santa Rita East’s economic performance. As the primary beneficiary of Santa Rita East, AEP consolidates Santa Rita East into its financial statements. See the table below for the classification of Santa Rita’s assets and liabilities on the balance sheets. AEP recognized $8 million of PTC attributable to Santa Rita East for the three and nine months ended September 30, 2019 which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Santa Rita East is presented in Noncontrolling Interests on the balance sheets. As of September 30, 2019 , AEP recorded $118 million of Noncontrolling Interests related to Santa Rita East in Equity on the balance sheets. American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities September 30, 2019 Registrant Subsidiary Other Consolidated VIEs AEP Texas Restoration Funding Apple Blossom and Black Oak Santa Rita East (in millions) ASSETS Current Assets $ 1.2 $ 5.7 $ 17.0 Net Property, Plant and Equipment — 233.3 466.6 Other Noncurrent Assets 235.3 12.5 0.8 Total Assets $ 236.5 $ 251.5 $ 484.4 LIABILITIES AND EQUITY Current Liabilities $ 14.4 $ 2.2 $ 3.5 Noncurrent Liabilities 220.9 4.6 7.5 Equity 1.2 244.7 473.4 Total Liabilities and Equity $ 236.5 $ 251.5 $ 484.4 Significant Equity Method Investments in Unconsolidated Entities The equity method of accounting is used for equity investments where AEP exercises significant influence but does 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 regularly monitors and evaluates 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. Sempra Renewables LLC In April 2019, AEP acquired a 50% interest in five wind farms in multiple states as part of the purchase of Sempra Renewables LLC. The wind farms are joint ventures with BP Wind Energy who holds the other 50% interest. All five wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. Another jointly-owned wind farm has a PPA with SWEPCo for a portion of its energy production. The joint venture wind farms are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the wind farms and therefore applies the equity method of accounting. As of September 30, 2019 , AEP’s investment in the five joint venture wind farms was $389 million . The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. The investment is comprised of a historical investment of $417 million plus a basis difference of $(19) million . AEP’s equity earnings associated with the five joint venture wind farms were losses of $3 million and $6 million for the three and nine months ended September 30, 2019 , respectively. AEP recognized $7 million and $21 million of PTC attributable to the joint venture wind farms for the three and nine months ended September 30, 2019 , respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income. ETT 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% interest in ETT and AEP Transmission Partner held the remaining 0.5% membership interest in ETT. In July 2019, AEP Transmission Partner was merged into AEP Transmission Holdco, increasing AEP Transmission Holdco’s interest in ETT to 50% . As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of September 30, 2019 and December 31, 2018 , AEP’s investment in ETT was $693 million and $666 million , respectively. AEP’s equity earnings associated with ETT were $16 million and $15 million for the three months ended September 30, 2019 and 2018 , respectively. AEP’s equity earnings associated with ETT were $49 million and $46 million for the nine months ended September 30, 2019 and 2018

Revenue from Contracts with Cus

Revenue from Contracts with Customers	9 Months Ended
	Sep. 30, 2019
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 tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue: Three Months Ended September 30, 2019 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 $ 1,060.2 $ 588.0 $ — $ — $ — $ — $ 1,648.2 Commercial Revenues 612.5 290.9 — — — — 903.4 Industrial Revenues 566.0 99.3 — — — 1.5 666.8 Other Retail Revenues 49.2 10.6 — — — — 59.8 Total Retail Revenues 2,287.9 988.8 — — — 1.5 3,278.2 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 231.3 — — 77.1 — (34.2 ) 274.2 Transmission Revenues (b) 77.8 110.9 269.4 — — (217.2 ) 240.9 Marketing, Competitive Retail and Renewable Revenues — — — 415.4 — 0.5 415.9 Total Wholesale and Competitive Retail Revenues 309.1 110.9 269.4 492.5 — (250.9 ) 931.0 Other Revenues from Contracts with Customers (c) 47.3 42.9 4.5 14.8 35.6 (42.2 ) 102.9 Total Revenues from Contracts with Customers 2,644.3 1,142.6 273.9 507.3 35.6 (291.6 ) 4,312.1 Other Revenues: Alternative Revenues (c) 1.2 5.1 (0.9 ) — — (16.8 ) (11.4 ) Other Revenues (c) — 38.9 — 26.4 (11.2 ) (39.8 ) 14.3 Total Other Revenues 1.2 44.0 (0.9 ) 26.4 (11.2 ) (56.6 ) 2.9 Total Revenues $ 2,645.5 $ 1,186.6 $ 273.0 $ 533.7 $ 24.4 $ (348.2 ) $ 4,315.0 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million . The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. Three Months Ended September 30, 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 $ 1,048.7 $ 612.2 $ — $ — $ — $ — $ 1,660.9 Commercial Revenues 612.8 330.9 — — — — 943.7 Industrial Revenues 578.8 128.8 — — — — 707.6 Other Retail Revenues 49.1 10.7 — — — — 59.8 Total Retail Revenues (a) 2,289.4 1,082.6 — — — — 3,372.0 Wholesale and Competitive Retail Revenues: Generation Revenues (b) 224.2 — — 115.1 — (98.5 ) 240.8 Transmission Revenues (c) 72.8 88.0 201.4 — — (241.6 ) 120.6 Marketing, Competitive Retail and Renewable Revenues — — — 399.1 — — 399.1 Total Wholesale and Competitive Retail Revenues 297.0 88.0 201.4 514.2 — (340.1 ) 760.5 Other Revenues from Contracts with Customers (e) 40.3 69.9 0.7 12.7 21.5 49.5 194.6 Total Revenues from Contracts with Customers 2,626.7 1,240.5 202.1 526.9 21.5 (290.6 ) 4,327.1 Other Revenues: Alternative Revenues (d) 0.2 (37.9 ) (14.9 ) — — — (52.6 ) Other Revenues (e) 9.8 8.9 — (5.3 ) 2.2 43.0 58.6 Total Other Revenues 10.0 (29.0 ) (14.9 ) (5.3 ) 2.2 43.0 6.0 Total Revenues $ 2,636.7 $ 1,211.5 $ 187.2 $ 521.6 $ 23.7 $ (247.6 ) $ 4,333.1 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $147 million . The remaining affiliated amounts were immaterial. (d) The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (e) Amounts include affiliated and nonaffiliated revenues. Three Months Ended September 30, 2019 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 192.0 $ — $ 315.7 $ 198.2 $ 395.6 $ 231.9 $ 222.9 Commercial Revenues 110.6 — 147.2 138.3 180.5 122.2 144.3 Industrial Revenues 32.2 — 152.2 138.7 67.1 84.1 92.3 Other Retail Revenues 7.5 — 18.5 1.9 3.1 24.9 2.3 Total Retail Revenues 342.3 — 633.6 477.1 646.3 463.1 461.8 Wholesale Revenues: Generation Revenues (a) — — 70.4 102.1 — 21.1 50.7 Transmission Revenues (b) 97.7 256.4 26.2 6.4 13.7 (3.4 ) 30.0 Total Wholesale Revenues 97.7 256.4 96.6 108.5 13.7 17.7 80.7 Other Revenues from Contracts with Customers (c) 8.2 4.5 18.7 26.6 41.0 5.1 7.0 Total Revenues from Contracts with Customers 448.2 260.9 748.9 612.2 701.0 485.9 549.5 Other Revenues: Alternative Revenues (d) (0.7 ) (1.2 ) 6.6 (1.1 ) 12.4 7.1 (4.0 ) Other Revenues (d) 41.8 — — — (2.8 ) — — Total Other Revenues 41.1 (1.2 ) 6.6 (1.1 ) 9.6 7.1 (4.0 ) Total Revenues $ 489.3 $ 259.7 $ 755.5 $ 611.1 $ 710.6 $ 493.0 $ 545.5 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $194 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 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. Three Months Ended September 30, 2018 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 178.8 $ — $ 320.9 $ 207.4 $ 433.5 $ 220.8 $ 214.1 Commercial Revenues 107.9 — 155.1 138.0 222.9 119.9 140.4 Industrial Revenues 32.1 — 157.6 150.2 96.3 82.4 89.6 Other Retail Revenues 7.4 — 19.2 1.7 3.3 24.5 2.2 Total Retail Revenues (a) 326.2 — 652.8 497.3 756.0 447.6 446.3 Wholesale Revenues: Generation Revenues (b) — — 74.5 93.6 — 12.5 53.2 Transmission Revenues (c) 73.6 206.6 20.9 6.2 14.8 13.5 29.5 Total Wholesale Revenues 73.6 206.6 95.4 99.8 14.8 26.0 82.7 Other Revenues from Contracts with Customers (d) 7.5 0.2 15.9 22.4 (29.9 ) 5.5 6.6 Total Revenues from Contracts with Customers 407.3 206.8 764.1 619.5 740.9 479.1 535.6 Other Revenues: Alternative Revenues (e) (1.0 ) (12.4 ) (1.2 ) 1.5 (36.9 ) 2.3 (0.3 ) Other Revenues (f) 27.1 — (0.9 ) 8.7 74.3 — — Total Other Revenues 26.1 (12.4 ) (2.1 ) 10.2 37.4 2.3 (0.3 ) Total Revenues $ 433.4 $ 194.4 $ 762.0 $ 629.7 $ 778.3 $ 481.4 $ 535.3 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $146 million . The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e) The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (f) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2019 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 $ 2,797.6 $ 1,609.1 $ — $ — $ — $ — $ 4,406.7 Commercial Revenues 1,641.2 889.4 — — — — 2,530.6 Industrial Revenues 1,647.3 332.6 — — — — 1,979.9 Other Retail Revenues 136.1 32.8 — — — — 168.9 Total Retail Revenues 6,222.2 2,863.9 — — — — 9,086.1 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 661.9 — — 282.0 — (105.5 ) 838.4 Transmission Revenues (b) 215.4 324.0 814.3 — — (603.6 ) 750.1 Marketing, Competitive Retail and Renewable Revenues — — — 1,088.5 — 0.5 1,089.0 Total Wholesale and Competitive Retail Revenues 877.3 324.0 814.3 1,370.5 — (708.6 ) 2,677.5 Other Revenues from Contracts with Customers (c) 128.8 127.6 12.6 4.5 80.4 (113.6 ) 240.3 Total Revenues from Contracts with Customers 7,228.3 3,315.5 826.9 1,375.0 80.4 (822.2 ) 12,003.9 Other Revenues: Alternative Revenues (c) (55.7 ) 21.5 (18.6 ) — — (60.3 ) (113.1 ) Other Revenues (c) — 117.3 — 53.2 (6.7 ) (109.2 ) 54.6 Total Other Revenues (55.7 ) 138.8 (18.6 ) 53.2 (6.7 ) (169.5 ) (58.5 ) Total Revenues $ 7,172.6 $ 3,454.3 $ 808.3 $ 1,428.2 $ 73.7 $ (991.7 ) $ 11,945.4 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million . The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 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 $ 2,906.9 $ 1,711.1 $ — $ — $ — $ — $ 4,618.0 Commercial Revenues 1,672.7 945.2 — — — — 2,617.9 Industrial Revenues 1,676.1 381.5 — — — — 2,057.6 Other Retail Revenues 139.4 31.8 — — — — 171.2 Total Retail Revenues (a) 6,395.1 3,069.6 — — — — 9,464.7 Wholesale and Competitive Retail Revenues: Generation Revenues (b) 686.5 — — 413.4 — (155.2 ) 944.7 Transmission Revenues (c) 208.4 272.6 633.9 — — (520.7 ) 594.2 Marketing, Competitive Retail and Renewable Revenues — — — 1,040.2 — — 1,040.2 Total Wholesale and Competitive Retail Revenues 894.9 272.6 633.9 1,453.6 — (675.9 ) 2,579.1 Other Revenues from Contracts with Customers (e) 121.8 165.1 11.1 15.0 64.8 1.8 379.6 Total Revenues from Contracts with Customers 7,411.8 3,507.3 645.0 1,468.6 64.8 (674.1 ) 12,423.4 Other Revenues: Alternative Revenues (d) (19.2 ) (48.3 ) (39.8 ) — — — (107.3 ) Other Revenues (e) 1.1 51.9 — 18.8 6.7 — 78.5 Total Other Revenues (18.1 ) 3.6 (39.8 ) 18.8 6.7 — (28.8 ) Total Revenues $ 7,393.7 $ 3,510.9 $ 605.2 $ 1,487.4 $ 71.5 $ (674.1 ) $ 12,394.6 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $87 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $444 million . The remaining affiliated amounts were immaterial. (d) The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (e) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2019 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 454.9 $ — $ 944.7 $ 558.8 $ 1,155.5 $ 519.6 $ 503.7 Commercial Revenues 314.5 — 421.5 371.4 573.7 304.3 371.1 Industrial Revenues 98.8 — 444.3 411.9 233.9 238.1 257.2 Other Retail Revenues 22.7 — 56.5 5.4 9.8 63.1 6.7 Total Retail Revenues 890.9 — 1,867.0 1,347.5 1,972.9 1,125.1 1,138.7 Wholesale Revenues: Generation Revenues (a) — — 200.1 327.4 — 35.5 152.7 Transmission Revenues (b) 282.0 775.3 77.6 18.8 42.0 21.9 78.0 Total Wholesale Revenues 282.0 775.3 277.7 346.2 42.0 57.4 230.7 Other Revenues from Contracts with Customers (c) 22.9 12.6 48.2 76.2 113.3 16.7 20.1 Total Revenues from Contracts with Customers 1,195.8 787.9 2,192.9 1,769.9 2,128.2 1,199.2 1,389.5 Other Revenues: Alternative Revenues (d) (0.4 ) (17.8 ) 11.2 (1.4 ) 22.0 (25.3 ) (47.4 ) Other Revenues (d) 122.6 — — — 3.8 — — Total Other Revenues 122.2 (17.8 ) 11.2 (1.4 ) 25.8 (25.3 ) (47.4 ) Total Revenues $ 1,318.0 $ 770.1 $ 2,204.1 $ 1,768.5 $ 2,154.0 $ 1,173.9 $ 1,342.1 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $587 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2018 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 453.6 $ — $ 1,017.3 $ 559.4 $ 1,258.4 $ 531.4 $ 512.4 Commercial Revenues 310.8 — 442.3 369.8 633.2 309.3 372.6 Industrial Revenues 94.8 — 457.3 428.0 287.4 228.7 254.0 Other Retail Revenues 21.7 — 57.6 5.4 9.8 65.2 6.4 Total Retail Revenues (a) 880.9 — 1,974.5 1,362.6 2,188.8 1,134.6 1,145.4 Wholesale Revenues: Generation Revenues (b) — — 194.1 349.7 — 26.7 168.8 Transmission Revenues (c) 229.6 612.9 60.2 16.9 42.8 29.4 77.3 Total Wholesale Revenues 229.6 612.9 254.3 366.6 42.8 56.1 246.1 Other Revenues from Contracts with Customers (d) 21.8 8.7 42.2 71.0 51.3 14.6 18.0 Total Revenues from Contracts with Customers 1,132.3 621.6 2,271.0 1,800.2 2,282.9 1,205.3 1,409.5 Other Revenues: Alternative Revenues (e) (1.1 ) (35.4 ) (20.7 ) (4.0 ) (47.2 ) 11.2 2.3 Other Revenues (f) 62.1 — (0.9 ) — 82.3 — — Total Other Revenues 61.0 (35.4 ) (21.6 ) (4.0 ) 35.1 11.2 2.3 Total Revenues $ 1,193.3 $ 586.2 $ 2,249.4 $ 1,796.2 $ 2,318.0 $ 1,216.5 $ 1,411.8 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $448 million . The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e) The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (f) Amounts include affiliated and nonaffiliated revenues. Fixed Performance Obligations The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2019 . 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 2023 Total (in millions) AEP $ 252.7 $ 209.7 $ 160.9 $ 285.5 $ 908.8 AEP Texas 96.8 — — — 96.8 AEPTCo 225.8 — — — 225.8 APCo 36.4 32.5 25.5 11.6 106.0 I&M 7.2 8.9 8.8 4.4 29.3 OPCo 17.8 7.5 — — 25.3 PSO 4.3 — — — 4.3 SWEPCo 9.8 — — — 9.8 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 material contract assets as of September 30, 2019 and 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 material contract liabilities as of September 30, 2019 and 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 September 30, 2019 and December 31, 2018. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information related to AEP Credit’s securitized accounts receivable. 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 September 30, 2019 December 31, 2018 (in millions) AEPTCo $ 69.9 $ 58.6 APCo 41.4 52.5 I&M 28.0 35.3 OPCo 29.2 46.1 PSO 10.3 12.4 SWEPCo 17.8 16.3

Significant Accounting Matters

Significant Accounting Matters (Policies)	9 Months Ended
	Sep. 30, 2019
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2019 is not necessarily indicative of results that may be expected for the year ending December 31, 2019 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2018 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 21, 2019 .
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 awards.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	9 Months Ended
	Sep. 30, 2019
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. 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS 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 and credit 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. 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 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. 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. 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)

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	9 Months Ended
	Sep. 30, 2019
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly traded securities issued by AEP.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and 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.
Fair Value Assets and Liabilities Measured on Recurring Basis	Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes Amortization of Ex

Income Taxes Amortization of Excess ADIT not Subject to Normalization Requirements Policy (Policies)	9 Months Ended
	Sep. 30, 2019
Amortization of Excess ADIT Not Subject to Normalization Requirements [Line Items]
Amortization of Excess ADIT Not Subject to Normalization Requirements Policy [Table Text Block]	The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods. Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR ratably during each interim period due to the variability of pretax book income between interim periods and the application of an annual estimated ETR.

Leases (Policies)

Leases (Policies)	9 Months Ended
	Sep. 30, 2019
Lease Policy	Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Variable Interest Entities an_2

Variable Interest Entities and Equity Method Investments Variable Interest Entities and Equity Method Investments (Policies)	9 Months Ended
	Sep. 30, 2019
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.
Equity Method Investments	The equity method of accounting is used for equity investments where AEP exercises significant influence but does 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 regularly monitors and evaluates 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.

Significant Accounting Matter_2

Significant Accounting Matters (Tables)	9 Months Ended
	Sep. 30, 2019
Basic and Diluted EPS Calculations	Three Months Ended September 30, 2019 2018 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 733.5 $ 577.6 Weighted Average Number of Basic Shares Outstanding 493.8 $ 1.49 493.0 $ 1.17 Weighted Average Dilutive Effect of Stock-Based Awards 1.7 (0.01 ) 0.9 — Weighted Average Number of Diluted Shares Outstanding 495.5 $ 1.48 493.9 $ 1.17 Nine Months Ended September 30, 2019 2018 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,767.6 $ 1,560.4 Weighted Average Number of Basic Shares Outstanding 493.6 $ 3.58 492.6 $ 3.17 Weighted Average Dilutive Effect of Stock-Based Awards 1.5 (0.01 ) 0.9 (0.01 ) Weighted Average Number of Diluted Shares Outstanding 495.1 $ 3.57 493.5 $ 3.16
Supplementary Information	September 30, 2019 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 348.8 $ 0.1 $ 3.5 $ 4.7 Restricted Cash 141.0 114.3 17.1 — Total Cash, Cash Equivalents and Restricted Cash $ 489.8 $ 114.4 $ 20.6 $ 4.7 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

Comprehensive Income (Tables)

Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2019
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Cash Flow Hedges Pension Three Months Ended September 30, 2019 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (127.2 ) $ (15.9 ) $ (87.6 ) $ (230.7 ) Change in Fair Value Recognized in AOCI 38.4 (0.8 ) (b) — 37.6 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — (0.1 ) Purchased Electricity for Resale (a) 8.5 — — 8.5 Amortization of Prior Service Cost (Credit) — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains) Losses — — 3.0 3.0 Reclassifications from AOCI, before Income Tax (Expense) Benefit 8.4 — (1.8 ) 6.6 Income Tax (Expense) Benefit 1.8 — (0.4 ) 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 6.6 — (1.4 ) 5.2 Net Current Period Other Comprehensive Income (Loss) 45.0 (0.8 ) (1.4 ) 42.8 Balance in AOCI as of September 30, 2019 $ (82.2 ) $ (16.7 ) $ (89.0 ) $ (187.9 ) Cash Flow Hedges Pension Three Months Ended September 30, 2018 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (30.4 ) $ (15.3 ) $ (49.1 ) $ (94.8 ) Change in Fair Value Recognized in AOCI 12.2 2.3 — 14.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — (0.1 ) Purchased Electricity for Resale (a) (5.8 ) — — (5.8 ) Interest Expense (a) — 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains) Losses — — 3.2 3.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit (5.9 ) 0.4 (1.8 ) (7.3 ) Income Tax (Expense) Benefit (1.3 ) 0.1 (0.4 ) (1.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (4.6 ) 0.3 (1.4 ) (5.7 ) Net Current Period Other Comprehensive Income (Loss) 7.6 2.6 (1.4 ) 8.8 Balance in AOCI as of September 30, 2018 $ (22.8 ) $ (12.7 ) $ (50.5 ) $ (86.0 ) AEP Cash Flow Hedges Pension Nine Months Ended September 30, 2019 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (23.0 ) $ (12.6 ) $ (84.8 ) $ (120.4 ) Change in Fair Value Recognized in AOCI (92.3 ) (4.5 ) (b) — (96.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — (0.1 ) Purchased Electricity for Resale (a) 42.0 — — 42.0 Interest Expense (a) — 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — — (14.3 ) (14.3 ) Amortization of Actuarial (Gains) Losses — — 9.0 9.0 Reclassifications from AOCI, before Income Tax (Expense) Benefit 41.9 0.5 (5.3 ) 37.1 Income Tax (Expense) Benefit 8.8 0.1 (1.1 ) 7.8 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 33.1 0.4 (4.2 ) 29.3 Net Current Period Other Comprehensive Income (Loss) (59.2 ) (4.1 ) (4.2 ) (67.5 ) Balance in AOCI as of September 30, 2019 $ (82.2 ) $ (16.7 ) $ (89.0 ) $ (187.9 ) Cash Flow Hedges Securities Interest Available Pension Nine Months Ended September 30, 2018 Commodity Rate for Sale and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (28.4 ) $ (13.0 ) $ 11.9 $ (38.3 ) $ (67.8 ) Change in Fair Value Recognized in AOCI 30.4 2.3 — — 32.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.1 ) — — — (0.1 ) Purchased Electricity for Resale (a) (23.6 ) — — — (23.6 ) Interest Expense (a) — 0.9 — — 0.9 Amortization of Prior Service Cost (Credit) — — — (14.7 ) (14.7 ) Amortization of Actuarial (Gains) Losses — — — 9.6 9.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit (23.7 ) 0.9 — (5.1 ) (27.9 ) Income Tax (Expense) Benefit (5.0 ) 0.2 — (1.1 ) (5.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (18.7 ) 0.7 — (4.0 ) (22.0 ) Net Current Period Other Comprehensive Income (Loss) 11.7 3.0 — (4.0 ) 10.7 ASU 2018-02 Adoption (6.1 ) (2.7 ) — (8.2 ) (17.0 ) ASU 2016-01 Adoption — — (11.9 ) — (11.9 ) Balance in AOCI as of September 30, 2018 $ (22.8 ) $ (12.7 ) $ — $ (50.5 ) $ (86.0 ) AEP Texas Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (3.9 ) $ (10.6 ) $ (14.5 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (0.1 ) (0.1 ) Amortization of Actuarial (Gains) Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit — — — Income Tax (Expense) Benefit — — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — — — Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2019 $ (3.6 ) $ (10.6 ) $ (14.2 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (4.9 ) $ (9.8 ) $ (14.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4 — 0.4 Income Tax (Expense) Benefit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3 — 0.3 Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2018 $ (4.6 ) $ (9.8 ) $ (14.4 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (4.4 ) $ (10.7 ) $ (15.1 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.1 ) (0.1 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.6 0.1 0.7 Income Tax (Expense) Benefit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.5 0.1 0.6 Net Current Period Other Comprehensive Income (Loss) 0.8 0.1 0.9 Balance in AOCI as of September 30, 2019 $ (3.6 ) $ (10.6 ) $ (14.2 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (4.5 ) $ (8.1 ) $ (12.6 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.1 ) (0.1 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0 0.1 1.1 Income Tax (Expense) Benefit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8 0.1 0.9 Net Current Period Other Comprehensive Income (Loss) 0.8 0.1 0.9 ASU 2018-02 Adoption (0.9 ) (1.8 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (4.6 ) $ (9.8 ) $ (14.4 ) APCo Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ 1.4 $ (8.1 ) $ (6.7 ) Change in Fair Value Recognized in AOCI (0.3 ) — (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains) Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit — (0.8 ) (0.8 ) Income Tax (Expense) Benefit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — (0.6 ) (0.6 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) (0.6 ) (0.9 ) Balance in AOCI as of September 30, 2019 $ 1.1 $ (8.7 ) $ (7.6 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ 2.3 $ (2.7 ) $ (0.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.4 ) — (0.4 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains) Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.4 ) (0.9 ) (1.3 ) Income Tax (Expense) Benefit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3 ) (0.7 ) (1.0 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) (0.7 ) (1.0 ) Balance in AOCI as of September 30, 2018 $ 2.0 $ (3.4 ) $ (1.4 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ 1.8 $ (6.8 ) $ (5.0 ) Change in Fair Value Recognized in AOCI (0.3 ) — (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.5 ) — (0.5 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains) Losses — 1.6 1.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.5 ) (2.4 ) (2.9 ) Income Tax (Expense) Benefit (0.1 ) (0.5 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.4 ) (1.9 ) (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) (1.9 ) (2.6 ) Balance in AOCI as of September 30, 2019 $ 1.1 $ (8.7 ) $ (7.6 ) Cash Flow Hedges Pension Nine Months Ended September 30, 2018 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ — $ 2.2 $ (0.9 ) $ 1.3 Change in Fair Value Recognized in AOCI (0.7 ) — — (0.7 ) Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (a) 0.9 — — 0.9 Interest Expense (a) — (0.9 ) — (0.9 ) Amortization of Prior Service Cost (Credit) — — (3.9 ) (3.9 ) Amortization of Actuarial (Gains) Losses — — 1.0 1.0 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.9 (0.9 ) (2.9 ) (2.9 ) Income Tax (Expense) Benefit 0.2 (0.2 ) (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.7 (0.7 ) (2.3 ) (2.3 ) Net Current Period Other Comprehensive Income (Loss) — (0.7 ) (2.3 ) (3.0 ) ASU 2018-02 Adoption — 0.5 (0.2 ) 0.3 Balance in AOCI as of September 30, 2018 $ — $ 2.0 $ (3.4 ) $ (1.4 ) I&M Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (10.7 ) $ (2.4 ) $ (13.1 ) Change in Fair Value Recognized in AOCI 0.4 — 0.4 Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit — — — Income Tax (Expense) Benefit — — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — — — Net Current Period Other Comprehensive Income (Loss) 0.4 — 0.4 Balance in AOCI as of September 30, 2019 $ (10.3 ) $ (2.4 ) $ (12.7 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (12.2 ) $ (1.7 ) $ (13.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4 — 0.4 Income Tax (Expense) Benefit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3 — 0.3 Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2018 $ (11.9 ) $ (1.7 ) $ (13.6 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (11.5 ) $ (2.3 ) $ (13.8 ) Change in Fair Value Recognized in AOCI 0.4 — 0.4 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains) Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0 (0.1 ) 0.9 Income Tax (Expense) Benefit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8 (0.1 ) 0.7 Net Current Period Other Comprehensive Income (Loss) 1.2 (0.1 ) 1.1 Balance in AOCI as of September 30, 2019 $ (10.3 ) $ (2.4 ) $ (12.7 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (10.7 ) $ (1.4 ) $ (12.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains) Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.5 — 1.5 Income Tax (Expense) Benefit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.2 — 1.2 ASU 2018-02 Adoption (2.4 ) (0.3 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (11.9 ) $ (1.7 ) $ (13.6 ) OPCo Cash Flow Hedge – Three Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of June 30, 2019 $ 0.3 Change in Fair Value Recognized in AOCI (0.2 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.1 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1 ) Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) Balance in AOCI as of September 30, 2019 $ — Cash Flow Hedge – Three Months Ended September 30, 2018 Interest Rate (in millions) Balance in AOCI as of June 30, 2018 $ 1.7 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.5 ) Income Tax (Expense) Benefit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.4 ) Balance in AOCI as of September 30, 2018 $ 1.3 Cash Flow Hedge – Nine Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of December 31, 2018 $ 1.0 Change in Fair Value Recognized in AOCI (0.2 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.0 ) Income Tax (Expense) Benefit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (1.0 ) Balance in AOCI as of September 30, 2019 $ — Cash Flow Hedge – Nine Months Ended September 30, 2018 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) (1.3 ) 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 0.4 Balance in AOCI as of September 30, 2018 $ 1.3 PSO Cash Flow Hedge – Three Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of June 30, 2019 $ 1.6 Change in Fair Value Recognized in AOCI (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.2 Income Tax (Expense) Benefit 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.1 Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2019 $ 1.4 Cash Flow Hedge – Three Months Ended September 30, 2018 Interest Rate (in millions) Balance in AOCI as of June 30, 2018 $ 2.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.2 ) Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2 ) Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2018 $ 2.4 Cash Flow Hedge – Nine Months Ended September 30, 2019 Interest Rate (in millions) Balance in AOCI as of December 31, 2018 $ 2.1 Change in Fair Value Recognized in AOCI (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.5 ) Income Tax (Expense) Benefit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) Balance in AOCI as of September 30, 2019 $ 1.4 Cash Flow Hedge – Nine Months Ended September 30, 2018 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) (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.9 ) Income Tax (Expense) Benefit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.7 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) ASU 2018-02 Adoption 0.5 Balance in AOCI as of September 30, 2018 $ 2.4 SWEPCo Cash Flow Hedge – Pension Three Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2019 $ (2.5 ) $ (2.7 ) $ (5.2 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit — (0.3 ) (0.3 ) Income Tax (Expense) Benefit — — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — (0.3 ) (0.3 ) Net Current Period Other Comprehensive Income (Loss) 0.3 (0.3 ) — Balance in AOCI as of September 30, 2019 $ (2.2 ) $ (3.0 ) $ (5.2 ) Cash Flow Hedge – Pension Three Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of June 30, 2018 $ (6.4 ) $ 1.7 $ (4.7 ) Change in Fair Value Recognized in AOCI 2.3 — 2.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains) Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5 (0.4 ) 0.1 Income Tax (Expense) Benefit 0.1 (0.1 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4 (0.3 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 2.7 (0.3 ) 2.4 Balance in AOCI as of September 30, 2018 $ (3.7 ) $ 1.4 $ (2.3 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2019 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2018 $ (3.3 ) $ (2.1 ) $ (5.4 ) Change in Fair Value Recognized in AOCI 0.3 — 0.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains) Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0 (1.1 ) (0.1 ) Income Tax (Expense) Benefit 0.2 (0.2 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8 (0.9 ) (0.1 ) Net Current Period Other Comprehensive Income (Loss) 1.1 (0.9 ) 0.2 Balance in AOCI as of September 30, 2019 $ (2.2 ) $ (3.0 ) $ (5.2 ) Cash Flow Hedge – Pension Nine Months Ended September 30, 2018 Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 2.0 $ (4.0 ) Change in Fair Value Recognized in AOCI 2.3 — 2.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.6 — 1.6 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains) Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.6 (1.3 ) 0.3 Income Tax (Expense) Benefit 0.3 (0.3 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.3 (1.0 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 3.6 (1.0 ) 2.6 ASU 2018-02 Adoption (1.3 ) 0.4 (0.9 ) Balance in AOCI as of September 30, 2018 $ (3.7 ) $ 1.4 $ (2.3 ) (a) Amounts reclassified to the referenced line item on the statements of income. (b) The change in fair value includes $2 million and $6 million

Rate Matters (Tables)

Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2019
Regulated Generating Unit Expected to be Retired by 2020	Gross Accumulated Net Accelerated Materials and Supplies Cost of Expected Remaining (dollars in millions) $ 106.6 $ 80.6 $ 26.0 $ 21.9 $ 3.2 $ 5.1 2020 27 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” discussion below for additional information.
Regulatory Assets Pending Final Regulatory Approval	AEP September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs – Unrecovered Plant $ 50.3 $ 50.3 Kentucky Deferred Purchase Power Expenses 26.2 14.5 Oklaunion Power Station Accelerated Depreciation 21.9 5.5 Other Regulatory Assets Pending Final Regulatory Approval 5.4 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs – Asset Retirement Obligation Costs 37.8 35.3 Storm-Related Costs (a) — 152.4 Other Regulatory Assets Pending Final Regulatory Approval 26.8 20.7 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 168.4 $ 288.0 (a) In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information. (b) In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million , 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 Texas September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Rate Case Expense $ 2.3 $ 0.2 Storm-Related Costs (a) — 152.4 Total Regulatory Assets Pending Final Regulatory Approval $ 2.3 $ 152.6 (a) In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information. APCo September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs – Materials and Supplies $ 5.1 $ 9.0 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs – Asset Retirement Obligation Costs 37.8 35.3 Other Regulatory Assets Pending Final Regulatory Approval — 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 42.9 $ 44.9 (a) In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million , 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 September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Study Costs $ 10.7 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.1 3.3 Total Regulatory Assets Pending Final Regulatory Approval $ 10.8 $ 3.3 OPCo September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 1.0 Total Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 1.0 PSO September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Oklaunion Power Station Accelerated Depreciation $ 21.9 $ 5.5 Regulatory Assets Currently Not Earning a Return Other Regulatory Assets Pending Final Regulatory Approval — 0.5 Total Regulatory Assets Pending Final Regulatory Approval $ 21.9 $ 6.0 SWEPCo September 30, December 31, 2019 2018 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs – Unrecovered Plant $ 50.3 $ 50.3 Other Regulatory Assets Pending Final Regulatory Approval 0.3 0.3 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation - Arkansas, Louisiana 6.8 5.3 Rate Case Expense – Texas 1.4 4.9 Other Regulatory Assets Pending Final Regulatory Approval 4.2 3.6 Total Regulatory Assets Pending Final Regulatory Approval $ 63.0 $ 64.4

Commitments, Guarantees and C_2

Commitments, Guarantees and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2019
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 204.4 October 2019 to October 2020 AEP Texas 2.2 July 2020 OPCo 3.6 April 2020 to September 2020

Acquisitions and Impairments Ac

Acquisitions and Impairments Acquisitions and Impairments (Tables)	9 Months Ended
	Sep. 30, 2019
Business Combinations [Abstract]
Purchase Price Allocation of an Acquisition	Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019 Assets: Liabilities and Equity: Net Purchase Price (in millions) Current Assets $ 9.7 Current Liabilities $ 12.9 Property, Plant and Equipment 238.1 Asset Retirement Obligations 5.7 Investment in Joint Ventures 405.9 Total Liabilities 18.6 Other Noncurrent Assets 82.9 Noncontrolling Interest 134.8 Total Assets $ 736.6 Liabilities and Noncontrolling Interest $ 153.4 $ 583.2

Benefit Plans (Tables)

Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2019
Components of Net Periodic Benefit Cost	AEP Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 23.8 $ 24.4 $ 2.4 $ 2.9 Interest Cost 51.1 46.9 12.6 11.8 Expected Return on Plan Assets (74.0 ) (72.6 ) (23.4 ) (25.6 ) Amortization of Prior Service Credit — — (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 14.4 21.3 5.5 2.7 Net Periodic Benefit Cost (Credit) $ 15.3 $ 20.0 $ (20.2 ) $ (25.5 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 71.6 $ 73.2 $ 7.1 $ 8.7 Interest Cost 153.3 140.8 37.9 35.5 Expected Return on Plan Assets (222.0 ) (217.7 ) (70.3 ) (76.7 ) Amortization of Prior Service Credit — — (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 43.2 63.9 16.6 7.9 Net Periodic Benefit Cost (Credit) $ 46.1 $ 60.2 $ (60.5 ) $ (76.4 ) AEP Texas Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 2.2 $ 2.3 $ 0.1 $ 0.3 Interest Cost 4.4 4.0 1.0 0.9 Expected Return on Plan Assets (6.5 ) (6.4 ) (1.9 ) (2.1 ) Amortization of Prior Service Credit — — (1.5 ) (1.5 ) Amortization of Net Actuarial Loss 1.2 1.8 0.5 0.2 Net Periodic Benefit Cost (Credit) $ 1.3 $ 1.7 $ (1.8 ) $ (2.2 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 6.5 $ 6.9 $ 0.5 $ 0.7 Interest Cost 13.1 12.0 3.0 2.8 Expected Return on Plan Assets (19.4 ) (19.2 ) (5.8 ) (6.4 ) Amortization of Prior Service Credit — — (4.4 ) (4.4 ) Amortization of Net Actuarial Loss 3.7 5.4 1.4 0.6 Net Periodic Benefit Cost (Credit) $ 3.9 $ 5.1 $ (5.3 ) $ (6.7 ) APCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 2.4 $ 2.4 $ 0.2 $ 0.3 Interest Cost 6.3 5.8 2.2 2.1 Expected Return on Plan Assets (9.4 ) (9.1 ) (3.7 ) (4.0 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 1.8 2.6 1.0 0.4 Net Periodic Benefit Cost (Credit) $ 1.1 $ 1.7 $ (2.8 ) $ (3.7 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 7.1 $ 7.0 $ 0.7 $ 0.8 Interest Cost 18.9 17.6 6.5 6.2 Expected Return on Plan Assets (28.1 ) (27.4 ) (11.0 ) (12.0 ) Amortization of Prior Service Credit — — (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 5.3 7.9 2.8 1.4 Net Periodic Benefit Cost (Credit) $ 3.2 $ 5.1 $ (8.5 ) $ (11.1 ) I&M Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 3.3 $ 3.4 $ 0.3 $ 0.4 Interest Cost 6.0 5.6 1.5 1.4 Expected Return on Plan Assets (9.1 ) (9.0 ) (2.8 ) (3.1 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 1.6 2.5 0.7 0.3 Net Periodic Benefit Cost (Credit) $ 1.8 $ 2.5 $ (2.7 ) $ (3.4 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 10.0 $ 10.2 $ 1.0 $ 1.2 Interest Cost 17.9 16.6 4.4 4.1 Expected Return on Plan Assets (27.5 ) (26.8 ) (8.5 ) (9.3 ) Amortization of Prior Service Credit — — (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 4.9 7.4 2.0 0.9 Net Periodic Benefit Cost (Credit) $ 5.3 $ 7.4 $ (8.2 ) $ (10.2 ) OPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 1.9 $ 2.0 $ 0.2 $ 0.2 Interest Cost 4.8 4.4 1.4 1.3 Expected Return on Plan Assets (7.3 ) (7.2 ) (2.7 ) (2.9 ) Amortization of Prior Service Credit — — (1.8 ) (1.7 ) Amortization of Net Actuarial Loss 1.3 2.0 0.6 0.3 Net Periodic Benefit Cost (Credit) $ 0.7 $ 1.2 $ (2.3 ) $ (2.8 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 5.9 $ 5.8 $ 0.6 $ 0.7 Interest Cost 14.3 13.3 4.1 3.9 Expected Return on Plan Assets (22.0 ) (21.6 ) (8.1 ) (8.8 ) Amortization of Prior Service Credit — — (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 4.0 6.0 1.9 0.8 Net Periodic Benefit Cost (Credit) $ 2.2 $ 3.5 $ (6.7 ) $ (8.6 ) PSO Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 1.6 $ 1.7 $ 0.2 $ 0.1 Interest Cost 2.6 2.5 0.7 0.6 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.3 ) (1.3 ) Amortization of Prior Service Credit — — (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 0.7 1.1 0.3 0.1 Net Periodic Benefit Cost (Credit) $ 0.9 $ 1.3 $ (1.2 ) $ (1.6 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 4.9 $ 5.3 $ 0.5 $ 0.5 Interest Cost 7.9 7.4 2.0 1.8 Expected Return on Plan Assets (12.2 ) (12.1 ) (3.9 ) (4.1 ) Amortization of Prior Service Credit — — (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 2.2 3.3 0.9 0.4 Net Periodic Benefit Cost (Credit) $ 2.8 $ 3.9 $ (3.7 ) $ (4.6 ) SWEPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 2.1 $ 2.4 $ 0.2 $ 0.2 Interest Cost 3.1 2.8 0.7 0.7 Expected Return on Plan Assets (4.4 ) (4.4 ) (1.5 ) (1.6 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 0.9 1.3 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.7 $ 2.1 $ (1.5 ) $ (1.8 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Service Cost $ 6.4 $ 7.0 $ 0.6 $ 0.7 Interest Cost 9.3 8.5 2.3 2.1 Expected Return on Plan Assets (13.3 ) (13.1 ) (4.5 ) (4.8 ) Amortization of Prior Service Credit — — (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 2.6 3.8 1.1 0.5 Net Periodic Benefit Cost (Credit) $ 5.0 $ 6.2 $ (4.4 ) $ (5.4 )

Business Segments (Tables)

Business Segments (Tables)	9 Months Ended
	Sep. 30, 2019
Segment Reporting Information [Line Items]
Reportable Segment Information	Three Months Ended September 30, 2019 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 54.0 $ — $ — $ 54.0 Sales to AEP Affiliates 205.7 — — 205.7 Other Revenues — — — — Total Revenues $ 259.7 $ — $ — $ 259.7 Interest Income $ 0.4 $ 32.3 $ (31.9 ) (a) $ 0.8 Interest Expense 26.4 31.9 (31.9 ) (a) 26.4 Income Tax Expense 30.0 0.1 — 30.1 Net Income $ 107.3 $ 0.3 (b) $ — $ 107.6 Three Months Ended September 30, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 46.0 $ — $ — $ 46.0 Sales to AEP Affiliates 148.4 — — 148.4 Other Revenues — — — — Total Revenues $ 194.4 $ — $ — $ 194.4 Interest Income $ 0.2 $ 26.0 $ (25.7 ) (a) $ 0.5 Interest Expense 19.8 25.7 (25.7 ) (a) 19.8 Income Tax Expense 18.4 (0.8 ) — 17.6 Net Income $ 77.1 $ 1.0 (b) $ — $ 78.1 Nine Months Ended September 30, 2019 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 162.1 $ — $ — $ 162.1 Sales to AEP Affiliates 608.0 — — 608.0 Other Revenues — — — — Total Revenues $ 770.1 $ — $ — $ 770.1 Interest Income $ 0.8 $ 89.7 $ (88.4 ) (a) $ 2.1 Interest Expense 69.5 88.4 (88.4 ) (a) 69.5 Income Tax Expense 90.5 0.2 — 90.7 Net Income $ 347.1 $ 0.8 (b) $ — $ 347.9 Nine Months Ended September 30, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 132.3 $ — $ — $ 132.3 Sales to AEP Affiliates 453.8 — — 453.8 Other Revenues 0.1 — — 0.1 Total Revenues $ 586.2 $ — $ — $ 586.2 Interest Income $ 0.4 $ 76.2 $ (75.3 ) (a) $ 1.3 Interest Expense 60.7 75.3 (75.3 ) (a) 60.7 Income Tax Expense 63.7 — — 63.7 Net Income $ 243.6 $ 0.6 (b) $ — $ 244.2 September 30, 2019 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 9,267.4 $ — $ — $ 9,267.4 Accumulated Depreciation and Amortization 368.8 — — 368.8 Total Transmission Property – Net $ 8,898.6 $ — $ — $ 8,898.6 Notes Receivable - Affiliated $ — $ 3,511.9 $ (3,511.9 ) (c) $ — Total Assets $ 9,363.5 $ 3,589.0 (d) $ (3,599.8 ) (e) $ 9,352.7 Total Long-term Debt $ 3,550.0 $ 3,511.9 $ (3,550.0 ) (c) $ 3,511.9 December 31, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) 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 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Includes the elimination of AEPTCo Parent’s investments in State Transcos. (e) Primarily relates to the elimination of Notes Receivable from the State Transcos. Three Months Ended September 30, 2019 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,598.9 $ 1,147.3 $ 65.5 $ 501.2 $ 2.1 $ — $ 4,315.0 Other Operating Segments 46.6 39.3 207.5 32.5 22.3 (348.2 ) — Total Revenues $ 2,645.5 $ 1,186.6 $ 273.0 $ 533.7 $ 24.4 $ (348.2 ) $ 4,315.0 Net Income (Loss) $ 438.4 $ 133.7 $ 127.0 $ 88.7 $ (53.9 ) $ — $ 733.9 Three Months Ended September 30, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,610.2 $ 1,180.9 $ 51.9 $ 486.5 $ 3.6 $ — $ 4,333.1 Other Operating Segments 26.5 30.6 135.3 35.1 20.1 (247.6 ) — Total Revenues $ 2,636.7 $ 1,211.5 $ 187.2 $ 521.6 $ 23.7 $ (247.6 ) $ 4,333.1 Net Income (Loss) $ 345.6 $ 145.2 $ 74.2 $ 5.1 $ 9.6 $ — $ 579.7 Nine Months Ended September 30, 2019 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 7,087.6 $ 3,328.7 $ 196.5 $ 1,323.8 $ 8.8 $ — $ 11,945.4 Other Operating Segments 85.0 125.6 611.8 104.4 64.9 (991.7 ) — Total Revenues $ 7,172.6 $ 3,454.3 $ 808.3 $ 1,428.2 $ 73.7 $ (991.7 ) $ 11,945.4 Net Income (Loss) $ 920.8 $ 421.6 $ 407.6 $ 133.1 $ (116.0 ) $ — $ 1,767.1 Nine Months Ended September 30, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 7,332.4 $ 3,450.0 $ 196.5 $ 1,399.3 $ 16.4 $ — $ 12,394.6 Other Operating Segments 61.3 60.9 408.7 88.1 55.1 (674.1 ) — Total Revenues $ 7,393.7 $ 3,510.9 $ 605.2 $ 1,487.4 $ 71.5 $ (674.1 ) $ 12,394.6 Net Income (Loss) $ 856.3 $ 384.6 $ 280.9 $ 61.8 $ (17.1 ) $ — $ 1,566.5 September 30, 2019 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 46,739.8 $ 19,283.9 $ 9,700.4 $ 1,661.6 $ 421.7 $ (354.5 ) (b) $ 77,452.9 Accumulated Depreciation and Amortization 14,359.3 3,907.3 383.8 99.8 196.4 (186.4 ) (b) 18,760.2 Total Property Plant and Equipment - Net $ 32,380.5 $ 15,376.6 $ 9,316.6 $ 1,561.8 $ 225.3 $ (168.1 ) (b) $ 58,692.7 Total Assets $ 40,746.1 $ 17,967.6 $ 10,606.7 $ 3,315.9 $ 5,002.3 (c) $ (3,737.9 ) (b) (d) $ 73,900.7 Long-term Debt Due Within One Year: Nonaffiliated $ 687.4 $ 391.5 $ 249.0 $ — $ (0.2 ) (e) $ — $ 1,327.7 Long-term Debt: Affiliated 59.0 — — 32.2 — (91.2 ) — Nonaffiliated 12,161.1 5,868.9 3,426.9 (0.3 ) 3,096.9 — 24,553.5 Total Long-term Debt $ 12,907.5 $ 6,260.4 $ 3,675.9 $ 31.9 $ 3,096.7 (e) $ (91.2 ) $ 25,881.2 December 31, 2018 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 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 — 21,648.2 Total Long-term Debt $ 12,559.0 $ 5,597.9 $ 2,973.6 $ 32.0 $ 2,266.4 (e) $ (82.2 ) $ 23,346.7 (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 finance 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)	9 Months Ended
	Sep. 30, 2019
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2019 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 424.3 — 94.7 37.1 7.3 21.6 6.9 Natural Gas MMBtus 53.2 — — — — — 12.5 Heating Oil and Gasoline Gallons 8.4 1.8 1.6 0.8 2.0 0.8 0.9 Interest Rate USD $ 140.1 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 600.0 $ — $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — $ —
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments September 30, 2019 Risk Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 337.0 $ 16.5 $ 1.9 $ 355.4 $ (168.7 ) $ 186.7 Long-term Risk Management Assets 319.0 10.0 25.3 354.3 (55.3 ) 299.0 Total Assets 656.0 26.5 27.2 709.7 (224.0 ) 485.7 Current Risk Management Liabilities 213.4 36.4 0.2 250.0 (174.7 ) 75.3 Long-term Risk Management Liabilities 281.7 87.4 — 369.1 (70.5 ) 298.6 Total Liabilities 495.1 123.8 0.2 619.1 (245.2 ) 373.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 160.9 $ (97.3 ) $ 27.0 $ 90.6 $ 21.2 $ 111.8 December 31, 2018 Risk Hedging Contracts Gross Amounts Gross Net Amounts of 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 AEP Texas Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — 0.1 0.1 Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Liabilities $ (0.4 ) $ — $ (0.4 ) December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 ) APCo Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 86.3 $ (29.8 ) $ 56.5 Long-term Risk Management Assets 4.1 (3.9 ) 0.2 Total Assets 90.4 (33.7 ) 56.7 Current Risk Management Liabilities 32.3 (31.2 ) 1.1 Long-term Risk Management Liabilities 4.4 (4.1 ) 0.3 Total Liabilities 36.7 (35.3 ) 1.4 Total MTM Derivative Contract Net Assets $ 53.7 $ 1.6 $ 55.3 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 I&M Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 30.5 $ (20.0 ) $ 10.5 Long-term Risk Management Assets 2.7 (2.6 ) 0.1 Total Assets 33.2 (22.6 ) 10.6 Current Risk Management Liabilities 21.0 (20.8 ) 0.2 Long-term Risk Management Liabilities 2.7 (2.7 ) — Total Liabilities 23.7 (23.5 ) 0.2 Total MTM Derivative Contract Net Assets $ 9.5 $ 0.9 $ 10.4 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 OPCo Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.2 — 7.2 Long-term Risk Management Liabilities 105.7 — 105.7 Total Liabilities 112.9 — 112.9 Total MTM Derivative Contract Net Liabilities $ (112.9 ) $ — $ (112.9 ) December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 ) PSO Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 21.9 $ (0.2 ) $ 21.7 Long-term Risk Management Assets — — — Total Assets 21.9 (0.2 ) 21.7 Current Risk Management Liabilities 0.5 (0.2 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.2 ) 0.3 Total MTM Derivative Contract Net Assets $ 21.4 $ — $ 21.4 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 SWEPCo Fair Value of Derivative Instruments September 30, 2019 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 9.8 $ (0.4 ) $ 9.4 Long-term Risk Management Assets — — — Total Assets 9.8 (0.4 ) 9.4 Current Risk Management Liabilities 2.1 (0.4 ) 1.7 Long-term Risk Management Liabilities 3.0 — 3.0 Total Liabilities 5.1 (0.4 ) 4.7 Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 December 31, 2018 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts – in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) 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 (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 Three Months Ended September 30, 2019 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.5 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.0 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.2 0.2 — — — Purchased Electricity for Resale 0.4 — 0.3 — — — — Other Operation (0.1 ) — (0.1 ) (0.1 ) (0.1 ) (0.1 ) — Maintenance (0.2 ) — — (0.1 ) — — — Regulatory Assets (a) (4.8 ) (0.2 ) 0.2 — (2.6 ) (0.1 ) (1.6 ) Regulatory Liabilities (a) 26.3 — 10.0 3.2 — 4.3 4.5 Total Gain (Loss) on Risk Management Contracts $ 43.1 $ (0.2 ) $ 10.6 $ 3.2 $ (2.7 ) $ 4.1 $ 2.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Three Months Ended September 30, 2018 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (0.7 ) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 19.3 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (0.5 ) (0.1 ) — — — Purchased Electricity for Resale 0.3 — 0.3 — — — — Other Operation 0.5 0.1 0.1 0.1 0.1 0.1 0.1 Maintenance 0.6 0.1 0.1 0.1 0.1 0.1 0.1 Regulatory Assets (a) (14.0 ) — — (3.5 ) (9.3 ) (0.6 ) (0.6 ) Regulatory Liabilities (a) 33.8 — 24.0 — — 3.9 1.5 Total Gain (Loss) on Risk Management Contracts $ 39.8 $ 0.2 $ 24.0 $ (3.4 ) $ (9.1 ) $ 3.5 $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts Nine Months Ended September 30, 2019 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 1.0 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 27.2 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.2 0.5 — — 0.1 Purchased Electricity for Resale 1.6 — 1.4 0.1 — — — Other Operation (0.6 ) (0.1 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Maintenance (0.6 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) — (0.1 ) Regulatory Assets (a) (19.4 ) 0.3 0.4 0.2 (19.8 ) 0.9 (0.4 ) Regulatory Liabilities (a) 64.5 — (5.3 ) 17.2 — 26.6 22.9 Total Gain (Loss) on Risk Management Contracts $ 73.7 $ 0.1 $ (3.5 ) $ 17.8 $ (20.1 ) $ 27.4 $ 22.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Nine Months Ended September 30, 2018 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (9.4 ) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 31.7 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (1.3 ) (7.8 ) — — 0.1 Purchased Electricity for Resale 8.3 — 7.3 0.8 — — — Other Operation 1.3 0.3 0.2 0.2 0.3 0.2 0.2 Maintenance 1.5 0.3 0.3 0.2 0.3 0.2 0.2 Regulatory Assets (a) 29.2 — — (0.3 ) 31.8 (0.6 ) (1.7 ) Regulatory Liabilities (a) 206.2 — 127.3 11.7 0.6 34.8 7.6 Total Gain on Risk Management Contracts $ 268.8 $ 0.6 $ 133.8 $ 4.8 $ 33.0 $ 34.6 $ 6.4 (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 the Condensed Balance Sheet	Carrying Amount of the Hedged Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) September 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018 (in millions) Long-term Debt (a) $ (521.2 ) $ (478.3 ) $ (25.1 ) $ 17.4 (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	Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Gain (Loss) on Interest Rate Contracts: Gain (Loss) on Fair Value Hedging Instruments (a) $ 13.2 $ (6.3 ) $ 42.5 $ (28.1 ) Gain (Loss) on Fair Value Portion of Long-term Debt (a) (13.2 ) 6.3 (42.5 ) 28.1 (a) Gain (Loss) is included in Interest Expense on the statements of income.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2019 December 31, 2018 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) AEP Texas $ (3.6 ) $ (1.1 ) $ (4.4 ) $ (1.1 ) APCo 1.1 0.9 1.8 0.9 I&M (10.3 ) (1.6 ) (11.5 ) (1.6 ) OPCo — — 1.0 1.0 PSO 1.4 1.0 2.1 1.0 SWEPCo (2.2 ) (1.5 ) (3.3 ) (1.5 ) Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2019 December 31, 2018 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Gain (Loss) Net of Tax $ (82.2 ) $ (16.7 ) (a) $ (23.0 ) $ (12.6 ) Portion Expected to be Reclassed to Net Income During the Next Twelve Months (24.2 ) (3.7 ) 10.4 (1.1 ) (a) Includes $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information.
Liabilities Subject to Cross Default Provisions	September 30, 2019 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 $ 261.0 $ 3.4 $ 230.7 APCo 3.9 — 0.2 I&M 2.3 — 0.1 SWEPCo 4.7 — 2.8 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

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2019
Book Values and Fair Values of Long-term Debt	September 30, 2019 December 31, 2018 Company Book Value Fair Value Book Value Fair Value (in millions) AEP (a) $ 25,881.2 $ 29,729.1 $ 23,346.7 $ 24,093.9 AEP Texas 4,146.5 4,631.5 3,881.3 3,964.6 AEPTCo 3,511.9 3,984.9 2,823.0 2,782.4 APCo 4,362.9 5,370.2 4,062.6 4,473.3 I&M 3,031.5 3,497.3 3,035.4 3,070.2 OPCo 2,113.9 2,618.5 1,716.6 1,919.7 PSO 1,386.4 1,632.9 1,287.0 1,361.9 SWEPCo 2,656.9 2,983.0 2,713.4 2,670.2 (a) The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $887 million as of September 30, 2019 . See “Equity Units” section of Note 13 for additional information.
Other Temporary Investments	September 30, 2019 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 160.1 $ — $ — $ 160.1 Fixed Income Securities – Mutual Funds (b) 133.4 — (0.2 ) 133.2 Equity Securities – Mutual Funds 28.5 17.6 — 46.1 Total Other Temporary Investments $ 322.0 $ 17.6 $ (0.2 ) $ 339.4 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
Debt and Equity Securities Within Other Temporary Investments	Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Proceeds from Investment Sales $ 2.8 $ — $ 2.8 $ — Purchases of Investments 26.9 0.8 35.8 2.2 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — —
Nuclear Trust Fund Investments	September 30, 2019 December 31, 2018 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 17.4 $ — $ — $ 22.5 $ — $ — Fixed Income Securities: United States Government 1,047.4 67.8 (5.8 ) 996.1 26.7 (7.1 ) Corporate Debt 68.6 6.1 (1.7 ) 52.4 1.1 (1.9 ) State and Local Government 7.5 0.7 (0.2 ) 8.6 0.6 (0.2 ) Subtotal Fixed Income Securities 1,123.5 74.6 (7.7 ) 1,057.1 28.4 (9.2 ) Equity Securities - Domestic (a) 1,694.3 1,037.7 — 1,395.3 766.3 — Spent Nuclear Fuel and Decommissioning Trusts $ 2,835.2 $ 1,112.3 $ (7.7 ) $ 2,474.9 $ 794.7 $ (9.2 ) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $1 billion and $784 million and unrealized losses of $9 million and $18 million as of September 30, 2019 and December 31, 2018 , respectively. 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	Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (in millions) Proceeds from Investment Sales $ 671.9 $ 513.1 $ 871.4 $ 1,550.9 Purchases of Investments 689.1 521.2 915.7 1,589.0 Gross Realized Gains on Investment Sales 10.9 3.9 26.6 27.7 Gross Realized Losses on Investment Sales 7.1 3.5 15.1 22.2
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 334.9 After 1 year through 5 years 390.9 After 5 years through 10 years 199.2 After 10 years 198.5 Total $ 1,123.5
Fair Value, Assets and Liabilities Measured on Recurring Basis	AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 152.9 $ — $ — $ 7.2 $ 160.1 Fixed Income Securities – Mutual Funds 133.2 — — — 133.2 Equity Securities – Mutual Funds (b) 46.1 — — — 46.1 Total Other Temporary Investments 332.2 — — 7.2 339.4 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.6 228.2 407.7 (195.3 ) 446.2 Cash Flow Hedges: Commodity Hedges (c) — 17.6 2.9 (8.2 ) 12.3 Interest Rate Hedges — 1.9 — — 1.9 Fair Value Hedges — 25.3 — — 25.3 Total Risk Management Assets 5.6 273.0 410.6 (203.5 ) 485.7 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 8.0 17.4 Fixed Income Securities: United States Government — 1,047.4 — — 1,047.4 Corporate Debt — 68.6 — — 68.6 State and Local Government — 7.5 — — 7.5 Subtotal Fixed Income Securities — 1,123.5 — — 1,123.5 Equity Securities – Domestic (b) 1,694.3 — — — 1,694.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,703.7 1,123.5 — 8.0 2,835.2 Total Assets $ 2,041.5 $ 1,396.5 $ 410.6 $ (188.3 ) $ 3,660.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.1 $ 243.9 $ 231.6 $ (216.5 ) $ 264.1 Cash Flow Hedges: Commodity Hedges (c) — 49.1 68.7 (8.2 ) 109.6 Fair Value Hedges — 0.2 — — 0.2 Total Risk Management Liabilities $ 5.1 $ 293.2 $ 300.3 $ (224.7 ) $ 373.9 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) (f) 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) (f) $ 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 Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 114.3 $ — $ — $ — $ 114.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 0.4 $ — $ — $ 0.4 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 17.1 $ — $ — $ — $ 17.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 31.4 57.3 (32.0 ) 56.7 Total Assets $ 17.1 $ 31.4 $ 57.3 $ (32.0 ) $ 73.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 33.2 $ 1.8 $ (33.6 ) $ 1.4 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 21.9 $ 10.2 $ (21.5 ) $ 10.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 8.0 17.4 Fixed Income Securities: United States Government — 1,047.4 — — 1,047.4 Corporate Debt — 68.6 — — 68.6 State and Local Government — 7.5 — — 7.5 Subtotal Fixed Income Securities — 1,123.5 — — 1,123.5 Equity Securities - Domestic (b) 1,694.3 — — — 1,694.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,703.7 1,123.5 — 8.0 2,835.2 Total Assets $ 1,703.7 $ 1,145.4 $ 10.2 $ (13.5 ) $ 2,845.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.3 $ 1.3 $ (22.4 ) $ 0.2 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Liabilities: (in millions) Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 112.5 $ — $ 112.9 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 22.0 $ (0.3 ) $ 21.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.4 $ (0.3 ) $ 0.3 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2019 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.8 $ (0.4 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 4.9 $ (0.4 ) $ 4.7 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 (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 September 30, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2019, $(8) million in periods 2020-2022 and $(1) million in periods 2025-2032; Level 3 matures $40 million in 2019, $114 million in periods 2020-2022, $26 million in periods 2023-2024 and $(4) 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2019 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2019 $ 112.7 $ 68.5 $ 12.3 $ (111.5 ) $ 27.8 $ 8.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 30.2 13.8 3.1 — 4.1 3.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 22.1 — — — — — Settlements (67.4 ) (28.1 ) (7.2 ) 1.1 (11.2 ) (6.7 ) Transfers into Level 3 (c) (d) 3.5 — — — — — Transfers out of Level 3 (d) 6.6 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) (0.3 ) 1.3 0.7 (2.1 ) 0.9 (0.5 ) Balance as of September 30, 2019 $ 110.3 $ 55.5 $ 8.9 $ (112.5 ) $ 21.6 $ 4.9 Three Months Ended September 30, 2018 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2018 $ 172.3 $ 60.0 $ 13.2 $ (86.9 ) $ 24.3 $ 4.9 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 19.9 9.0 1.9 — 3.7 1.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 1.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 10.4 — — — — — Settlements (56.0 ) (19.8 ) (5.5 ) 0.6 (10.8 ) (2.7 ) Transfers into Level 3 (c) (d) 2.3 — — — — — Transfers out of Level 3 (d) (1.2 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 12.0 17.3 (0.2 ) (8.9 ) 0.4 (0.4 ) Balance as of September 30, 2018 $ 161.2 $ 66.5 $ 9.4 $ (95.2 ) $ 17.6 $ 3.5 Nine Months Ended September 30, 2019 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2018 $ 131.2 $ 57.8 $ 8.9 $ (99.4 ) $ 9.5 $ 2.3 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 14.6 (14.1 ) 4.6 (0.9 ) 13.5 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 32.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (42.8 ) — — — — — Settlements (114.6 ) (41.9 ) (12.6 ) 4.6 (23.0 ) (10.1 ) Transfers into Level 3 (c) (d) 0.4 — — — — — Transfers out of Level 3 (d) 1.4 (0.7 ) (0.4 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 87.2 54.4 8.4 (16.8 ) 21.6 6.7 Balance as of September 30, 2019 $ 110.3 $ 55.5 $ 8.9 $ (112.5 ) $ 21.6 $ 4.9 Nine Months Ended September 30, 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) (a) (b) 150.9 104.4 14.7 1.3 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 (a) 9.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 16.4 — — — — — Settlements (212.3 ) (128.3 ) (21.9 ) 3.0 (24.3 ) (1.3 ) Transfers into Level 3 (c) (d) 16.5 — — — — — Transfers out of Level 3 (d) (2.5 ) — (0.3 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 142.4 65.7 9.3 32.9 17.6 3.7 Balance as of September 30, 2018 $ 161.2 $ 66.5 $ 9.4 $ (95.2 ) $ 17.6 $ 3.5 (a) Included in revenues on the statements of income. (b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (c) Represents existing assets or liabilities that were previously categorized as Level 2. (d) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (e) 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	AEP Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 298.8 $ 286.8 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 180.10 $ 31.34 Natural Gas Contracts — 4.5 Discounted Cash Flow Forward Market Price (b) 1.96 2.62 2.25 FTRs 111.8 9.0 Discounted Cash Flow Forward Market Price (a) (10.40 ) 11.65 0.54 Total $ 410.6 $ 300.3 December 31, 2018 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 APCo Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 3.6 $ 1.1 Discounted Cash Flow Forward Market Price $ 12.93 $ 59.25 $ 31.28 FTRs 53.7 0.7 Discounted Cash Flow Forward Market Price (0.91 ) 10.14 1.63 Total $ 57.3 $ 1.8 December 31, 2018 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 I&M Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.2 $ 0.7 Discounted Cash Flow Forward Market Price $ 12.93 $ 59.25 $ 31.28 FTRs 8.0 0.6 Discounted Cash Flow Forward Market Price (1.76 ) 7.26 0.87 Total $ 10.2 $ 1.3 December 31, 2018 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 OPCo Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ — $ 112.5 Discounted Cash Flow Forward Market Price $ 27.47 $ 65.81 $ 40.30 December 31, 2018 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 PSO Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 22.0 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.87 ) $ 0.93 $ (2.19 ) December 31, 2018 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 ) SWEPCo Significant Unobservable Inputs September 30, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 4.5 Discounted Cash Flow Forward Market Price (b) $ 1.96 $ 2.62 $ 2.25 FTRs 9.8 0.4 Discounted Cash Flow Forward Market Price (a) (6.87 ) 0.93 (2.19 ) Total $ 9.8 $ 4.9 December 31, 2018 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 (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)	9 Months Ended
	Sep. 30, 2019
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 Case Pending Case Pending I&M (Michigan) Order Issued Case Pending Case Pending SWEPCo (Louisiana) Case Pending – Rates Implemented (b) Case Pending – Rates Implemented (b) Case Pending – Rates Implemented (b) SWEPCo (Texas) Order Issued 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 addressed in a current pending case. (b) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval.
Schedule of Effective Income Tax Rate Reconciliation	Three Months Ended September 30, Nine Months Ended September 30, Company 2019 2018 2019 2018 AEP 5.2 % (16.2 )% 1.7 % 5.6 % AEP Texas 15.1 % 12.6 % (25.3 )% 14.9 % AEPTCo 21.9 % 18.4 % 20.7 % 20.7 % APCo (3.9 )% (962.2 )% (19.1 )% (13.8 )% I&M (2.7 )% 15.9 % (2.1 )% 10.4 % OPCo 13.9 % (46.4 )% 14.2 % 4.6 % PSO 6.4 % 5.6 % 4.6 % 8.7 % SWEPCo (0.6 )% 9.8 % — % 11.4 %

Leases (Tables)

Leases (Tables)	9 Months Ended
	Sep. 30, 2019
Lease Rental Costs	Three Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 64.4 $ 4.0 $ 0.6 $ 4.9 $ 23.7 $ 4.9 $ 1.5 $ 1.8 Finance Lease Cost: Amortization of Right-of-Use Assets 16.5 1.5 0.1 2.0 1.6 1.1 0.8 2.8 Interest on Lease Liabilities 4.1 0.3 — 0.8 0.8 0.2 0.1 0.7 Total Lease Rental Costs (a) $ 85.0 $ 5.8 $ 0.7 $ 7.7 $ 26.1 $ 6.2 $ 2.4 $ 5.3 Nine Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 200.3 $ 12.2 $ 1.7 $ 14.5 $ 70.0 $ 13.8 $ 5.0 $ 5.7 Finance Lease Cost: Amortization of Right-of-Use Assets 45.0 3.8 0.1 5.0 4.2 2.6 2.2 8.2 Interest on Lease Liabilities 12.2 1.0 — 2.2 2.3 0.5 0.4 2.2 Total Lease Rental Costs (a) $ 257.5 $ 17.0 $ 1.8 $ 21.7 $ 76.5 $ 16.9 $ 7.6 $ 16.1 (a) Excludes variable and short-term lease costs, which were immaterial for the three and nine months ended September 30, 2019 .
Supplemental Balance Sheet Information Related to Leases	September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo Weighted-Average Remaining Lease Term (years): Operating Leases 5.31 7.05 2.43 6.25 4.05 8.10 7.06 6.63 Finance Leases 5.87 6.86 0.58 6.33 6.72 6.58 6.24 5.34 Weighted-Average Discount Rate: Operating Leases 3.61 % 3.79 % 3.13 % 3.67 % 3.45 % 3.79 % 3.68 % 3.80 % Finance Leases 6.02 % 4.71 % 9.33 % 8.19 % 8.61 % 4.66 % 4.73 % 5.03 % Nine Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows Used for Operating Leases $ 163.6 $ 11.4 $ 1.7 $ 14.1 $ 52.5 $ 13.8 $ 4.9 $ 5.3 Operating Cash Flows Used for Finance Leases 11.0 1.0 — 2.2 2.2 0.5 0.4 1.1 Financing Cash Flows Used for Finance Leases 44.5 3.8 — 5.0 4.0 2.6 2.2 8.1 Non-cash Acquisitions Under Operating Leases $ 108.9 $ 12.7 $ — $ 8.6 $ 16.6 $ 34.6 $ 7.3 $ 10.6
Property, Plant and Equipment and Related Obligations Under Finance Leases	September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Finance Leases: Generation $ 134.9 $ — $ — $ 41.3 $ 28.5 $ — $ 2.6 $ 34.2 Other Property, Plant and Equipment 335.9 41.9 0.2 18.4 37.1 24.7 20.7 50.0 Total Property, Plant and Equipment 470.8 41.9 0.2 59.7 65.6 24.7 23.3 84.2 Accumulated Amortization 162.7 10.9 0.2 17.8 22.8 6.6 9.1 26.2 Net Property, Plant and Equipment Under Finance Leases $ 308.1 $ 31.0 $ — $ 41.9 $ 42.8 $ 18.1 $ 14.2 $ 58.0 Obligations Under Finance Leases: Noncurrent Liability $ 254.0 $ 25.8 $ — $ 35.2 $ 37.1 $ 14.5 $ 11.0 $ 50.5 Liability Due Within One Year 61.4 5.2 — 6.7 6.0 3.6 3.2 11.2 Total Obligations Under Finance Leases $ 315.4 $ 31.0 $ — $ 41.9 $ 43.1 $ 18.1 $ 14.2 $ 61.7
Operating Lease Assets and Related Obligations	September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Assets $ 990.0 $ 82.0 $ 4.6 $ 79.4 $ 295.3 $ 88.2 $ 37.1 $ 40.8 Obligations Under Operating Leases: Noncurrent Liability $ 801.1 $ 71.1 $ 2.2 $ 64.8 $ 234.0 $ 75.9 $ 31.2 $ 32.5 Liability Due Within One Year 228.8 11.7 2.3 15.3 82.0 12.8 6.0 5.9 Total Obligations Under Operating Leases $ 1,029.9 $ 82.8 $ 4.5 $ 80.1 $ 316.0 $ 88.7 $ 37.2 $ 38.4
Finance Lease Liabilities Rolling Future Minimum Lease Payments	Finance Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year 1 $ 76.8 $ 6.6 $ — $ 9.6 $ 9.0 $ 4.3 $ 3.8 $ 13.0 Year 2 67.0 6.1 — 8.8 8.2 3.9 3.1 11.6 Year 3 58.0 5.3 — 8.1 7.6 3.2 2.3 10.6 Year 4 49.0 4.9 — 7.5 7.1 2.5 2.1 9.5 Year 5 50.0 4.1 — 7.0 6.7 2.1 1.7 14.8 Later Years 76.1 9.8 — 11.3 20.9 5.3 3.7 7.5 Total Future Minimum Lease Payments 376.9 36.8 — 52.3 59.5 21.3 16.7 67.0 Less Imputed Interest 61.5 5.8 — 10.4 16.4 3.2 2.5 5.3 Estimated Present Value of Future Minimum Lease Payments $ 315.4 $ 31.0 $ — $ 41.9 $ 43.1 $ 18.1 $ 14.2 $ 61.7
Operating Lease Liabilities Rolling Future Minimum Lease Payments	Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Year 1 $ 267.5 $ 15.7 $ 2.4 $ 18.4 $ 92.2 $ 16.6 $ 7.4 $ 8.4 Year 2 252.4 15.2 1.5 16.4 88.4 13.9 6.6 8.2 Year 3 239.9 14.1 0.7 14.7 86.3 13.3 6.0 7.5 Year 4 154.2 13.0 0.3 12.5 48.0 12.4 5.5 7.2 Year 5 63.6 11.4 — 9.8 7.3 10.8 5.0 5.0 Later Years 184.1 27.8 — 20.1 22.0 38.3 12.7 12.4 Total Future Minimum Lease Payments 1,161.7 97.2 4.9 91.9 344.2 105.3 43.2 48.7 Less Imputed Interest 131.8 14.4 0.4 11.8 28.2 16.6 6.0 10.3 Estimated Present Value of Future Minimum Lease Payments $ 1,029.9 $ 82.8 $ 4.5 $ 80.1 $ 316.0 $ 88.7 $ 37.2 $ 38.4
Future Minimum Lease Payments	Finance 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 Imputed Interest 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 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 $ 46.6 AEP Texas 11.2 APCo 6.3 I&M 4.0 OPCo 7.4 PSO 4.3 SWEPCo 4.7
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 2019 $ 74.2 $ 37.1 2020 147.8 73.9 2021 147.8 73.9 2022 147.2 73.6 Total Future Minimum Lease Payments $ 517.0 $ 258.5 (a) AEP’s future minimum lease payments include equal shares from AEGCo and I&M.

Financing Activities (Tables)

Financing Activities (Tables)	9 Months Ended
	Sep. 30, 2019
Long-term Debt	Type of Debt September 30, 2019 December 31, 2018 (in millions) Senior Unsecured Notes $ 20,829.2 $ 18,903.3 Pollution Control Bonds 1,516.5 1,643.8 Notes Payable 189.1 204.7 Securitization Bonds 1,059.4 1,111.4 Spent Nuclear Fuel Obligation (a) 278.5 273.6 Junior Subordinated Notes (b) 786.8 — Other Long-term Debt 1,221.7 1,209.9 Total Long-term Debt Outstanding 25,881.2 23,346.7 Long-term Debt Due Within One Year 1,327.7 1,698.5 Long-term Debt $ 24,553.5 $ 21,648.2 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $322 million and $317 million as of September 30, 2019 and December 31, 2018 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) See “Equity Units” section below for additional information.
Long-term Debt Issuances	Principal Interest Company Type of Debt Amount (a) Rate Due Date Issuances: (in millions) (%) AEP Junior Subordinated Notes (b) $ 805.0 3.40 2024 AEP Texas Securitization Bonds 117.6 2.06 2025 AEP Texas Securitization Bonds 117.6 2.29 2029 AEP Texas Pollution Control Bonds 100.6 2.60 2029 AEP Texas Senior Unsecured Notes 300.0 4.15 2049 AEPTCo Senior Unsecured Notes 350.0 3.80 2049 AEPTCo Senior Unsecured Notes 350.0 3.15 2049 APCo Pollution Control Bonds 86.0 2.55 2024 APCo Senior Unsecured Notes 400.0 4.50 2049 I&M Notes Payable 62.8 Variable 2023 OPCo Senior Unsecured Notes 450.0 4.00 2049 PSO Senior Unsecured Notes 100.0 3.91 2029 PSO Senior Unsecured Notes 150.0 4.11 2034 PSO Senior Unsecured Notes 100.0 4.50 2049 Non-Registrant: AEGCo Pollution Control Bonds 45.0 1.35 2022 Transource Energy Other Long-term Debt 14.4 Variable 2020 Total Issuances $ 3,549.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. (b) See “Equity Units” section below for additional information.
Retirements and Principal Payments	Principal Interest Company Type of Debt Amount Paid Rate Due Date Retirements and Principal Payments: (in millions) (%) AEP Texas Senior Unsecured Notes $ 50.0 2.61 2019 AEP Texas Securitization Bonds 28.2 1.98 2020 AEP Texas Securitization Bonds 188.0 5.31 2020 AEP Texas Pollution Control Bonds 100.6 6.30 2029 APCo Pollution Control Bonds 86.0 1.90 2019 APCo Pollution Control Bonds 70.0 3.25 2019 APCo Securitization Bonds 24.4 2.01 2023 I&M Notes Payable 2.7 Variable 2019 I&M Notes Payable 4.3 Variable 2019 I&M Notes Payable 13.7 Variable 2020 I&M Notes Payable 17.9 Variable 2021 I&M Notes Payable 11.3 Variable 2022 I&M Notes Payable 16.0 Variable 2022 I&M Notes Payable 6.4 Variable 2023 I&M Other Long-term Debt 1.3 6.00 2025 OPCo Securitization Bonds 47.9 2.05 2019 OPCo Other Long-term Debt 0.1 1.15 2028 PSO Senior Unsecured Notes 250.0 5.15 2019 PSO Other Long-term Debt 0.4 3.00 2027 SWEPCo Pollution Control Bonds 53.5 1.60 2019 SWEPCo Other Long-term Debt 1.5 4.68 2028 SWEPCo Notes Payable 3.2 4.58 2032 Non-Registrant: AEGCo Pollution Control Bonds 45.0 Variable 2019 AEP Energy Notes Payable 0.1 5.75 2019 Transource Energy Other Long-term Debt 1.0 Variable 2020 Total Retirements and Principal Payments $ 1,023.5
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	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 September 30, 2019 Limit (in millions) AEP Texas $ 390.7 $ — $ 261.8 $ — $ (74.8 ) $ 500.0 AEPTCo 374.9 244.4 179.8 40.2 236.6 795.0 (a) APCo 225.4 232.2 90.4 61.8 (17.7 ) 600.0 I&M 120.4 66.0 53.1 17.2 (89.2 ) 500.0 OPCo 291.2 178.6 163.5 50.1 (17.6 ) 500.0 PSO 140.5 215.6 63.9 84.1 95.1 300.0 SWEPCo 105.1 81.4 57.8 11.2 6.4 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Nonutility Money Pool Activity	Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool September 30, 2019 (in millions) AEP Texas $ 8.0 $ 7.7 $ 7.7 SWEPCo 2.1 2.0 2.1
Direct Borrowing Activity	Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2019 September 30, 2019 Borrowing Limit (in millions) $ 1.3 $ 117.6 $ 1.3 $ 63.4 $ 1.3 $ 30.8 $ 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	Nine Months Ended September 30, 2019 2018 Maximum Interest Rate 3.43 % 2.52 % Minimum Interest Rate 1.83 % 1.81 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Average Interest Rate for Funds Borrowed from the Utility Money Pool Loaned to the Utility Money Pool for Nine Months Ended September 30, for Nine Months Ended September 30, Company 2019 2018 2019 2018 AEP Texas 2.71 % 2.25 % — % 2.29 % AEPTCo 2.72 % 2.26 % 2.57 % 2.04 % APCo 2.82 % 2.22 % 2.73 % 2.19 % I&M 2.56 % 2.16 % 2.73 % 2.06 % OPCo 2.80 % 2.18 % 2.68 % 2.47 % PSO 2.85 % 2.25 % 2.48 % 1.86 % SWEPCo 2.74 % 2.31 % 2.47 % 1.87 %
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool	Nine Months Ended September 30, 2019 Nine Months Ended September 30, 2018 Maximum Minimum Average Maximum Minimum 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 Loaned to Loaned to Loaned to Loaned to Loaned to 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 3.02 % 2.36 % 2.70 % 2.52 % 1.83 % 2.26 % SWEPCo 3.02 % 2.36 % 2.70 % 2.52 % 1.83 % 2.26 %
Maximum Minimum and Average Interest Rates for Funds Borrowed from and Loaned to AEP	Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2019 3.02 % 2.36 % 3.02 % 2.36 % 2.70 % 2.70 % 2018 2.52 % 1.76 % 2.52 % 1.76 % 2.26 % 2.27 %
Short Term Debt	September 30, 2019 December 31, 2018 Outstanding Interest Outstanding Interest Type of Debt Amount Rate (a) Amount Rate (a) (dollars in millions) Securitized Debt for Receivables (b) $ 750.0 2.56 % $ 750.0 2.16 % Commercial Paper 1,760.0 2.36 % 1,160.0 2.96 % Total Short-term Debt $ 2,510.0 $ 1,910.0 (a) Weighted-average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Comparative Accounts Receivable Information	Three Months Ended Nine Months Ended 2019 2018 2019 2018 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 2.37 % 2.27 % 2.56 % 2.06 % Net Uncollectible Accounts Receivable Written-Off $ 8.8 $ 9.6 $ 19.8 $ 19.0
Customer Accounts Receivable Managed Portfolio	September 30, 2019 December 31, 2018 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 923.3 $ 972.5 Short-term – Securitized Debt of Receivables 750.0 750.0 Delinquent Securitized Accounts Receivable 43.9 50.3 Bad Debt Reserves Related to Securitization 32.3 27.5 Unbilled Receivables Related to Securitization 216.2 281.4
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2019 December 31, 2018 (in millions) APCo $ 95.4 $ 133.3 I&M 156.2 152.9 OPCo 337.5 395.2 PSO 149.4 109.7 SWEPCo 168.6 150.3
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2019 2018 2019 2018 (in millions) APCo $ 1.2 $ 1.8 $ 5.8 $ 5.1 I&M 2.4 2.5 8.4 6.8 OPCo 6.4 7.2 22.1 18.8 PSO 2.0 2.3 6.2 6.0 SWEPCo 1.9 2.6 7.9 6.6
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2019 2018 2019 2018 (in millions) APCo $ 303.3 $ 334.1 $ 978.5 $ 1,079.2 I&M 485.3 498.4 1,378.9 1,401.7 OPCo 602.6 695.2 1,746.1 2,046.9 PSO 451.5 454.9 1,118.7 1,171.2 SWEPCo 480.7 512.6 1,247.0 1,364.6

Variable Interest Entities an_3

Variable Interest Entities and Equity Method Investments (Tables)	9 Months Ended
	Sep. 30, 2019
Consolidated Assets And Liabilities Of Variable Interest Entities	American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities September 30, 2019 Registrant Subsidiary Other Consolidated VIEs AEP Texas Restoration Funding Apple Blossom and Black Oak Santa Rita East (in millions) ASSETS Current Assets $ 1.2 $ 5.7 $ 17.0 Net Property, Plant and Equipment — 233.3 466.6 Other Noncurrent Assets 235.3 12.5 0.8 Total Assets $ 236.5 $ 251.5 $ 484.4 LIABILITIES AND EQUITY Current Liabilities $ 14.4 $ 2.2 $ 3.5 Noncurrent Liabilities 220.9 4.6 7.5 Equity 1.2 244.7 473.4 Total Liabilities and Equity $ 236.5 $ 251.5 $ 484.4

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	9 Months Ended
	Sep. 30, 2019
Disaggregated Revenues from Contracts with Customers	Three Months Ended September 30, 2019 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 $ 1,060.2 $ 588.0 $ — $ — $ — $ — $ 1,648.2 Commercial Revenues 612.5 290.9 — — — — 903.4 Industrial Revenues 566.0 99.3 — — — 1.5 666.8 Other Retail Revenues 49.2 10.6 — — — — 59.8 Total Retail Revenues 2,287.9 988.8 — — — 1.5 3,278.2 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 231.3 — — 77.1 — (34.2 ) 274.2 Transmission Revenues (b) 77.8 110.9 269.4 — — (217.2 ) 240.9 Marketing, Competitive Retail and Renewable Revenues — — — 415.4 — 0.5 415.9 Total Wholesale and Competitive Retail Revenues 309.1 110.9 269.4 492.5 — (250.9 ) 931.0 Other Revenues from Contracts with Customers (c) 47.3 42.9 4.5 14.8 35.6 (42.2 ) 102.9 Total Revenues from Contracts with Customers 2,644.3 1,142.6 273.9 507.3 35.6 (291.6 ) 4,312.1 Other Revenues: Alternative Revenues (c) 1.2 5.1 (0.9 ) — — (16.8 ) (11.4 ) Other Revenues (c) — 38.9 — 26.4 (11.2 ) (39.8 ) 14.3 Total Other Revenues 1.2 44.0 (0.9 ) 26.4 (11.2 ) (56.6 ) 2.9 Total Revenues $ 2,645.5 $ 1,186.6 $ 273.0 $ 533.7 $ 24.4 $ (348.2 ) $ 4,315.0 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million . The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. Three Months Ended September 30, 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 $ 1,048.7 $ 612.2 $ — $ — $ — $ — $ 1,660.9 Commercial Revenues 612.8 330.9 — — — — 943.7 Industrial Revenues 578.8 128.8 — — — — 707.6 Other Retail Revenues 49.1 10.7 — — — — 59.8 Total Retail Revenues (a) 2,289.4 1,082.6 — — — — 3,372.0 Wholesale and Competitive Retail Revenues: Generation Revenues (b) 224.2 — — 115.1 — (98.5 ) 240.8 Transmission Revenues (c) 72.8 88.0 201.4 — — (241.6 ) 120.6 Marketing, Competitive Retail and Renewable Revenues — — — 399.1 — — 399.1 Total Wholesale and Competitive Retail Revenues 297.0 88.0 201.4 514.2 — (340.1 ) 760.5 Other Revenues from Contracts with Customers (e) 40.3 69.9 0.7 12.7 21.5 49.5 194.6 Total Revenues from Contracts with Customers 2,626.7 1,240.5 202.1 526.9 21.5 (290.6 ) 4,327.1 Other Revenues: Alternative Revenues (d) 0.2 (37.9 ) (14.9 ) — — — (52.6 ) Other Revenues (e) 9.8 8.9 — (5.3 ) 2.2 43.0 58.6 Total Other Revenues 10.0 (29.0 ) (14.9 ) (5.3 ) 2.2 43.0 6.0 Total Revenues $ 2,636.7 $ 1,211.5 $ 187.2 $ 521.6 $ 23.7 $ (247.6 ) $ 4,333.1 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $147 million . The remaining affiliated amounts were immaterial. (d) The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (e) Amounts include affiliated and nonaffiliated revenues. Three Months Ended September 30, 2019 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 192.0 $ — $ 315.7 $ 198.2 $ 395.6 $ 231.9 $ 222.9 Commercial Revenues 110.6 — 147.2 138.3 180.5 122.2 144.3 Industrial Revenues 32.2 — 152.2 138.7 67.1 84.1 92.3 Other Retail Revenues 7.5 — 18.5 1.9 3.1 24.9 2.3 Total Retail Revenues 342.3 — 633.6 477.1 646.3 463.1 461.8 Wholesale Revenues: Generation Revenues (a) — — 70.4 102.1 — 21.1 50.7 Transmission Revenues (b) 97.7 256.4 26.2 6.4 13.7 (3.4 ) 30.0 Total Wholesale Revenues 97.7 256.4 96.6 108.5 13.7 17.7 80.7 Other Revenues from Contracts with Customers (c) 8.2 4.5 18.7 26.6 41.0 5.1 7.0 Total Revenues from Contracts with Customers 448.2 260.9 748.9 612.2 701.0 485.9 549.5 Other Revenues: Alternative Revenues (d) (0.7 ) (1.2 ) 6.6 (1.1 ) 12.4 7.1 (4.0 ) Other Revenues (d) 41.8 — — — (2.8 ) — — Total Other Revenues 41.1 (1.2 ) 6.6 (1.1 ) 9.6 7.1 (4.0 ) Total Revenues $ 489.3 $ 259.7 $ 755.5 $ 611.1 $ 710.6 $ 493.0 $ 545.5 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $194 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 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. Three Months Ended September 30, 2018 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 178.8 $ — $ 320.9 $ 207.4 $ 433.5 $ 220.8 $ 214.1 Commercial Revenues 107.9 — 155.1 138.0 222.9 119.9 140.4 Industrial Revenues 32.1 — 157.6 150.2 96.3 82.4 89.6 Other Retail Revenues 7.4 — 19.2 1.7 3.3 24.5 2.2 Total Retail Revenues (a) 326.2 — 652.8 497.3 756.0 447.6 446.3 Wholesale Revenues: Generation Revenues (b) — — 74.5 93.6 — 12.5 53.2 Transmission Revenues (c) 73.6 206.6 20.9 6.2 14.8 13.5 29.5 Total Wholesale Revenues 73.6 206.6 95.4 99.8 14.8 26.0 82.7 Other Revenues from Contracts with Customers (d) 7.5 0.2 15.9 22.4 (29.9 ) 5.5 6.6 Total Revenues from Contracts with Customers 407.3 206.8 764.1 619.5 740.9 479.1 535.6 Other Revenues: Alternative Revenues (e) (1.0 ) (12.4 ) (1.2 ) 1.5 (36.9 ) 2.3 (0.3 ) Other Revenues (f) 27.1 — (0.9 ) 8.7 74.3 — — Total Other Revenues 26.1 (12.4 ) (2.1 ) 10.2 37.4 2.3 (0.3 ) Total Revenues $ 433.4 $ 194.4 $ 762.0 $ 629.7 $ 778.3 $ 481.4 $ 535.3 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $146 million . The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e) The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (f) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2019 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 $ 2,797.6 $ 1,609.1 $ — $ — $ — $ — $ 4,406.7 Commercial Revenues 1,641.2 889.4 — — — — 2,530.6 Industrial Revenues 1,647.3 332.6 — — — — 1,979.9 Other Retail Revenues 136.1 32.8 — — — — 168.9 Total Retail Revenues 6,222.2 2,863.9 — — — — 9,086.1 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 661.9 — — 282.0 — (105.5 ) 838.4 Transmission Revenues (b) 215.4 324.0 814.3 — — (603.6 ) 750.1 Marketing, Competitive Retail and Renewable Revenues — — — 1,088.5 — 0.5 1,089.0 Total Wholesale and Competitive Retail Revenues 877.3 324.0 814.3 1,370.5 — (708.6 ) 2,677.5 Other Revenues from Contracts with Customers (c) 128.8 127.6 12.6 4.5 80.4 (113.6 ) 240.3 Total Revenues from Contracts with Customers 7,228.3 3,315.5 826.9 1,375.0 80.4 (822.2 ) 12,003.9 Other Revenues: Alternative Revenues (c) (55.7 ) 21.5 (18.6 ) — — (60.3 ) (113.1 ) Other Revenues (c) — 117.3 — 53.2 (6.7 ) (109.2 ) 54.6 Total Other Revenues (55.7 ) 138.8 (18.6 ) 53.2 (6.7 ) (169.5 ) (58.5 ) Total Revenues $ 7,172.6 $ 3,454.3 $ 808.3 $ 1,428.2 $ 73.7 $ (991.7 ) $ 11,945.4 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million . The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 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 $ 2,906.9 $ 1,711.1 $ — $ — $ — $ — $ 4,618.0 Commercial Revenues 1,672.7 945.2 — — — — 2,617.9 Industrial Revenues 1,676.1 381.5 — — — — 2,057.6 Other Retail Revenues 139.4 31.8 — — — — 171.2 Total Retail Revenues (a) 6,395.1 3,069.6 — — — — 9,464.7 Wholesale and Competitive Retail Revenues: Generation Revenues (b) 686.5 — — 413.4 — (155.2 ) 944.7 Transmission Revenues (c) 208.4 272.6 633.9 — — (520.7 ) 594.2 Marketing, Competitive Retail and Renewable Revenues — — — 1,040.2 — — 1,040.2 Total Wholesale and Competitive Retail Revenues 894.9 272.6 633.9 1,453.6 — (675.9 ) 2,579.1 Other Revenues from Contracts with Customers (e) 121.8 165.1 11.1 15.0 64.8 1.8 379.6 Total Revenues from Contracts with Customers 7,411.8 3,507.3 645.0 1,468.6 64.8 (674.1 ) 12,423.4 Other Revenues: Alternative Revenues (d) (19.2 ) (48.3 ) (39.8 ) — — — (107.3 ) Other Revenues (e) 1.1 51.9 — 18.8 6.7 — 78.5 Total Other Revenues (18.1 ) 3.6 (39.8 ) 18.8 6.7 — (28.8 ) Total Revenues $ 7,393.7 $ 3,510.9 $ 605.2 $ 1,487.4 $ 71.5 $ (674.1 ) $ 12,394.6 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $87 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $444 million . The remaining affiliated amounts were immaterial. (d) The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (e) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2019 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 454.9 $ — $ 944.7 $ 558.8 $ 1,155.5 $ 519.6 $ 503.7 Commercial Revenues 314.5 — 421.5 371.4 573.7 304.3 371.1 Industrial Revenues 98.8 — 444.3 411.9 233.9 238.1 257.2 Other Retail Revenues 22.7 — 56.5 5.4 9.8 63.1 6.7 Total Retail Revenues 890.9 — 1,867.0 1,347.5 1,972.9 1,125.1 1,138.7 Wholesale Revenues: Generation Revenues (a) — — 200.1 327.4 — 35.5 152.7 Transmission Revenues (b) 282.0 775.3 77.6 18.8 42.0 21.9 78.0 Total Wholesale Revenues 282.0 775.3 277.7 346.2 42.0 57.4 230.7 Other Revenues from Contracts with Customers (c) 22.9 12.6 48.2 76.2 113.3 16.7 20.1 Total Revenues from Contracts with Customers 1,195.8 787.9 2,192.9 1,769.9 2,128.2 1,199.2 1,389.5 Other Revenues: Alternative Revenues (d) (0.4 ) (17.8 ) 11.2 (1.4 ) 22.0 (25.3 ) (47.4 ) Other Revenues (d) 122.6 — — — 3.8 — — Total Other Revenues 122.2 (17.8 ) 11.2 (1.4 ) 25.8 (25.3 ) (47.4 ) Total Revenues $ 1,318.0 $ 770.1 $ 2,204.1 $ 1,768.5 $ 2,154.0 $ 1,173.9 $ 1,342.1 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $587 million . The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2018 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 453.6 $ — $ 1,017.3 $ 559.4 $ 1,258.4 $ 531.4 $ 512.4 Commercial Revenues 310.8 — 442.3 369.8 633.2 309.3 372.6 Industrial Revenues 94.8 — 457.3 428.0 287.4 228.7 254.0 Other Retail Revenues 21.7 — 57.6 5.4 9.8 65.2 6.4 Total Retail Revenues (a) 880.9 — 1,974.5 1,362.6 2,188.8 1,134.6 1,145.4 Wholesale Revenues: Generation Revenues (b) — — 194.1 349.7 — 26.7 168.8 Transmission Revenues (c) 229.6 612.9 60.2 16.9 42.8 29.4 77.3 Total Wholesale Revenues 229.6 612.9 254.3 366.6 42.8 56.1 246.1 Other Revenues from Contracts with Customers (d) 21.8 8.7 42.2 71.0 51.3 14.6 18.0 Total Revenues from Contracts with Customers 1,132.3 621.6 2,271.0 1,800.2 2,282.9 1,205.3 1,409.5 Other Revenues: Alternative Revenues (e) (1.1 ) (35.4 ) (20.7 ) (4.0 ) (47.2 ) 11.2 2.3 Other Revenues (f) 62.1 — (0.9 ) — 82.3 — — Total Other Revenues 61.0 (35.4 ) (21.6 ) (4.0 ) 35.1 11.2 2.3 Total Revenues $ 1,193.3 $ 586.2 $ 2,249.4 $ 1,796.2 $ 2,318.0 $ 1,216.5 $ 1,411.8 (a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $448 million . The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e) The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement. (f) Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations	Company 2019 2020-2021 2022-2023 After 2023 Total (in millions) AEP $ 252.7 $ 209.7 $ 160.9 $ 285.5 $ 908.8 AEP Texas 96.8 — — — 96.8 AEPTCo 225.8 — — — 225.8 APCo 36.4 32.5 25.5 11.6 106.0 I&M 7.2 8.9 8.8 4.4 29.3 OPCo 17.8 7.5 — — 25.3 PSO 4.3 — — — 4.3 SWEPCo 9.8 — — — 9.8
Affiliated Accounts Receivable Contracts with Customers	Company September 30, 2019 December 31, 2018 (in millions) AEPTCo $ 69.9 $ 58.6 APCo 41.4 52.5 I&M 28.0 35.3 OPCo 29.2 46.1 PSO 10.3 12.4 SWEPCo 17.8 16.3

Significant Accounting Matter_3

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Amounts Attributable to AEP Common Shareholders
Earnings Attributable to Common Shareholders	$ 733.5	$ 577.6	$ 1,767.6	$ 1,560.4
Weighted Average Number of Basic AEP Common Shares Outstanding	493,839,034	492,984,741	493,579,430	492,649,456
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$ 1.49	$ 1.17	$ 3.58	$ 3.17
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding	495,461,509	493,940,543	495,105,986	493,526,937
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	$ 1.48	$ 1.17	$ 3.57	$ 3.16
Organization and Summary of Significant Accounting Policies (Textuals)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount			0	0
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	$ 348.8		$ 348.8		$ 234.1
Restricted Cash	141		141		210
Total Cash, Cash Equivalents and Restricted Cash	489.8		489.8		444.1
Total Cash, Cash Equivalents and Restricted Cash	489.8	$ 937.5	489.8	$ 937.5	444.1	$ 412.6
AEP Texas Inc. [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	0.1		0.1		3.1
Restricted Cash	114.3		114.3		156.7
Total Cash, Cash Equivalents and Restricted Cash	114.4		114.4		159.8
Total Cash, Cash Equivalents and Restricted Cash	114.4	124.3	114.4	124.3	159.8	157.2
AEP Transmission Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	0	0	0	0	0	0
Appalachian Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	3.5		3.5		4.2
Restricted Cash	17.1		17.1		25.6
Total Cash, Cash Equivalents and Restricted Cash	20.6	12.1	20.6	12.1	29.8	19.2
Indiana Michigan Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	2.5	1.6	2.5	1.6	2.4	1.3
Ohio Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	4.7		4.7		4.9
Restricted Cash	0		0		27.6
Total Cash, Cash Equivalents and Restricted Cash	4.7	18.7	4.7	18.7	32.5	29.7
Public Service Co Of Oklahoma [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	2.9	1.9	2.9	1.9	2	1.6
Southwestern Electric Power Co [Member]
Amounts Attributable to AEP Common Shareholders
Earnings Attributable to Common Shareholders	110.5	88.2	144.5	137.6
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	$ 21.4	$ 2.5	$ 21.4	$ 2.5	$ 24.5	$ 1.6
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares	1,700,000	900,000	1,500,000	900,000
Dilutive Securities, Effect on Basic Earnings Per Share	$ (0.01)	$ 0	$ (0.01)	$ (0.01)

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions		3 Months Ended							9 Months Ended
		Sep. 30, 2019		Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019		Sep. 30, 2018
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		$ (230.7)			$ (120.4)	$ (94.8)		$ (67.8)	$ (120.4)		$ (67.8)
Change in Fair Value Recognized in AOCI		37.6				14.5			(96.8)		32.7
Commodity
Generation & Marketing Revenues		4,315				4,333.1			11,945.4		12,394.6
Interest Rate
Interest Expense		275.1				256.8			781.6		733.1
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		6.6				(7.3)			37.1		(27.9)
Income Tax (Expense) Benefit		40.6				(80.7)			30.7		93.5
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		5.2				(5.7)			29.3		(22)
Net Current Period Other Comprehensive Income (Loss)		42.8		$ (80)	(30.3)	8.8	$ 0.6	1.3	(67.5)		10.7
ASU 2018-02 Adoption								(3)
ASU 2016-01 Adoption								0
Ending Balance in AOCI		(187.9)		(230.7)		(86)	(94.8)		(187.9)		(86)
Securities Available for Sale [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI								11.9			11.9
Change in Fair Value Recognized in AOCI											0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit											0
Reclassification from AOCI, Net of Income Tax (Expense) Benefit											0
Net Current Period Other Comprehensive Income (Loss)											0
ASU 2018-02 Adoption											0
ASU 2016-01 Adoption											(11.9)
Ending Balance in AOCI						0					0
Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(87.6)			(84.8)	(49.1)		(38.3)	(84.8)		(38.3)
Change in Fair Value Recognized in AOCI		0				0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(1.8)				(1.8)			(5.3)		(5.1)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(1.4)				(1.4)			(4.2)		(4)
Net Current Period Other Comprehensive Income (Loss)		(1.4)				(1.4)			(4.2)		(4)
ASU 2018-02 Adoption											(8.2)
ASU 2016-01 Adoption											0
Ending Balance in AOCI		(89)		(87.6)		(50.5)	(49.1)		(89)		(50.5)
Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		42.8		(80)	(30.3)	8.8	0.6	1.3
ASU 2018-02 Adoption								(17)			(17)
ASU 2016-01 Adoption								(11.9)			(11.9)
Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(127.2)			(23)	(30.4)		(28.4)	(23)		(28.4)
Change in Fair Value Recognized in AOCI		38.4				12.2			(92.3)		30.4
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		8.4				(5.9)			41.9		(23.7)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		6.6				(4.6)			33.1		(18.7)
Net Current Period Other Comprehensive Income (Loss)		45				7.6			(59.2)		11.7
ASU 2018-02 Adoption											(6.1)
ASU 2016-01 Adoption											0
Ending Balance in AOCI		(82.2)		(127.2)		(22.8)	(30.4)		(82.2)		(22.8)
Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(15.9)			(12.6)	(15.3)		(13)	(12.6)		(13)
Change in Fair Value Recognized in AOCI		(0.8)	[1]			2.3			(4.5)	[1]	2.3
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0.4			0.5		0.9
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0.3			0.4		0.7
Net Current Period Other Comprehensive Income (Loss)		(0.8)				2.6			(4.1)		3
ASU 2018-02 Adoption											(2.7)
ASU 2016-01 Adoption											0
Ending Balance in AOCI		(16.7)		(15.9)		(12.7)	(15.3)		(16.7)		(12.7)
Generation and Marketing Revenues [Member]
Commodity
Generation & Marketing Revenues		501.2				486.5			1,323.8		1,399.3
Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		783.9				784.7			2,306.4		2,551.7
Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]					0.4			0.5		0.9
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(4.8)				(5)			(14.3)		(14.7)
Amortization of Actuarial (Gains) Losses		3				3.2			9		9.6
Income Tax (Expense) Benefit		1.4				(1.6)			7.8		(5.9)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Interest Rate
Interest Expense	[2]										0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)											0
Amortization of Actuarial (Gains) Losses											0
Income Tax (Expense) Benefit											0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]					0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(4.8)				(5)			(14.3)		(14.7)
Amortization of Actuarial (Gains) Losses		3				3.2			9		9.6
Income Tax (Expense) Benefit		(0.4)				(0.4)			(1.1)		(1.1)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]					0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0				0			0		0
Amortization of Actuarial (Gains) Losses		0				0			0		0
Income Tax (Expense) Benefit		1.8				(1.3)			8.8		(5)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]					0.4			0.5		0.9
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0				0			0		0
Amortization of Actuarial (Gains) Losses		0				0			0		0
Income Tax (Expense) Benefit		0				0.1			0.1		0.2
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Commodity
Generation & Marketing Revenues	[2]	(0.1)				(0.1)			(0.1)		(0.1)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Securities Available for Sale [Member]
Commodity
Generation & Marketing Revenues	[2]										0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Pension and OPEB [Member]
Commodity
Generation & Marketing Revenues	[2]	0				0			0		0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Generation & Marketing Revenues	[2]	(0.1)				(0.1)			(0.1)		(0.1)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Generation & Marketing Revenues	[2]	0				0			0		0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale	[2]	8.5				(5.8)			42		(23.6)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Securities Available for Sale [Member]
Commodity
Purchased Electricity for Resale	[2]										0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member]
Commodity
Purchased Electricity for Resale	[2]	0				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]	8.5				(5.8)			42		(23.6)
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		0
Apple Blossom and Black Oak [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense		2							6
AEP Texas Inc. [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(14.5)			(15.1)	(14.7)		(12.6)	(15.1)		(12.6)
Change in Fair Value Recognized in AOCI		0.3				0			0.3		0
Interest Rate
Interest Expense		35.8				37.3			92.7		108.9
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0.4			0.7		1.1
Income Tax (Expense) Benefit		13.7				8.3			(38.8)		26.4
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0.3			0.6		0.9
Net Current Period Other Comprehensive Income (Loss)		0.3		0.3	0.3	0.3	0.3	0.3	0.9		0.9
ASU 2018-02 Adoption								(0.9)
Ending Balance in AOCI		(14.2)		(14.5)		(14.4)	(14.7)		(14.2)		(14.4)
AEP Texas Inc. [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(10.6)			(10.7)	(9.8)		(8.1)	(10.7)		(8.1)
Change in Fair Value Recognized in AOCI		0				0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0			0.1		0.1
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0			0.1		0.1
Net Current Period Other Comprehensive Income (Loss)		0				0			0.1		0.1
ASU 2018-02 Adoption											(1.8)
Ending Balance in AOCI		(10.6)		(10.6)		(9.8)	(9.8)		(10.6)		(9.8)
AEP Texas Inc. [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		0.3		0.3	0.3	0.3	0.3	0.3
ASU 2018-02 Adoption								(2.7)			(2.7)
AEP Texas Inc. [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(3.9)			(4.4)	(4.9)		(4.5)	(4.4)		(4.5)
Change in Fair Value Recognized in AOCI		0.3				0			0.3		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0.4			0.6		1
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0.3			0.5		0.8
Net Current Period Other Comprehensive Income (Loss)		0.3				0.3			0.8		0.8
ASU 2018-02 Adoption											(0.9)
Ending Balance in AOCI		(3.6)		(3.9)		(4.6)	(4.9)		(3.6)		(4.6)
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]					0.4			0.6		1
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.1)							(0.1)		(0.1)
Amortization of Actuarial (Gains) Losses		0.1							0.2		0.2
Income Tax (Expense) Benefit		0				0.1			0.1		0.2
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]					0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.1)							(0.1)		(0.1)
Amortization of Actuarial (Gains) Losses		0.1							0.2		0.2
Income Tax (Expense) Benefit		0				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]					0.4			0.6		1
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0							0		0
Amortization of Actuarial (Gains) Losses		0							0		0
Income Tax (Expense) Benefit		0				0.1			0.1		0.2
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(6.7)			(5)	(0.4)		1.3	(5)		1.3
Change in Fair Value Recognized in AOCI		(0.3)				0			(0.3)		(0.7)
Interest Rate
Interest Expense		51.6				50.8			152.5		146
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.8)				(1.3)			(2.9)		(2.9)
Income Tax (Expense) Benefit		(3.9)				(78.9)			(47)		(35.1)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.6)				(1)			(2.3)		(2.3)
Net Current Period Other Comprehensive Income (Loss)		(0.9)		(0.9)	(0.8)	(1)	(1)	(1)	(2.6)		(3)
ASU 2018-02 Adoption								0.4
Ending Balance in AOCI		(7.6)		(6.7)		(1.4)	(0.4)		(7.6)		(1.4)
Appalachian Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(8.1)			(6.8)	(2.7)		(0.9)	(6.8)		(0.9)
Change in Fair Value Recognized in AOCI		0				0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.8)				(0.9)			(2.4)		(2.9)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.6)				(0.7)			(1.9)		(2.3)
Net Current Period Other Comprehensive Income (Loss)		(0.6)				(0.7)			(1.9)		(2.3)
ASU 2018-02 Adoption											(0.2)
Ending Balance in AOCI		(8.7)		(8.1)		(3.4)	(2.7)		(8.7)		(3.4)
Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		(0.9)		(0.9)	(0.8)	(1)	(1)	(1)
ASU 2018-02 Adoption								0.3			0.3
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI								0			0
Change in Fair Value Recognized in AOCI											(0.7)
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit											0.9
Reclassification from AOCI, Net of Income Tax (Expense) Benefit											0.7
Net Current Period Other Comprehensive Income (Loss)											0
ASU 2018-02 Adoption											0
Ending Balance in AOCI						0					0
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.4			1.8	2.3		2.2	1.8		2.2
Change in Fair Value Recognized in AOCI		(0.3)				0			(0.3)		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				(0.4)			(0.5)		(0.9)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				(0.3)			(0.4)		(0.7)
Net Current Period Other Comprehensive Income (Loss)		(0.3)				(0.3)			(0.7)		(0.7)
ASU 2018-02 Adoption											0.5
Ending Balance in AOCI		1.1		1.4		2	2.3		1.1		2
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		78.3				80.4			253.4		350.8
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]					(0.4)			(0.5)		(0.9)
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(1.4)				(1.3)			(4)		(3.9)
Amortization of Actuarial (Gains) Losses		0.6				0.4			1.6		1
Income Tax (Expense) Benefit		(0.2)				(0.3)			(0.6)		(0.6)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]					0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(1.4)				(1.3)			(4)		(3.9)
Amortization of Actuarial (Gains) Losses		0.6				0.4			1.6		1
Income Tax (Expense) Benefit		(0.2)				(0.2)			(0.5)		(0.6)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]										0
Amortization Of Pension And Other Postretirement Benefit Plans
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]					(0.4)			(0.5)		(0.9)
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0				0			0		0
Amortization of Actuarial (Gains) Losses		0				0			0		0
Income Tax (Expense) Benefit		0				(0.1)			(0.1)		(0.2)
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]
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]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(13.1)			(13.8)	(13.9)		(12.1)	(13.8)		(12.1)
Change in Fair Value Recognized in AOCI		0.4				0			0.4		0
Interest Rate
Interest Expense		28.8				34.5			85.9		95.6
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0.4			0.9		1.5
Income Tax (Expense) Benefit		(2.3)				13.7			(5.1)		26.8
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0.3			0.7		1.2
Net Current Period Other Comprehensive Income (Loss)		0.4		0.3	0.4	0.3	0.5	0.4	1.1		1.2
ASU 2018-02 Adoption								(2.4)
Ending Balance in AOCI		(12.7)		(13.1)		(13.6)	(13.9)		(12.7)		(13.6)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(2.4)			(2.3)	(1.7)		(1.4)	(2.3)		(1.4)
Change in Fair Value Recognized in AOCI		0				0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0			(0.1)		0
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0			(0.1)		0
Net Current Period Other Comprehensive Income (Loss)		0				0			(0.1)		0
ASU 2018-02 Adoption											(0.3)
Ending Balance in AOCI		(2.4)		(2.4)		(1.7)	(1.7)		(2.4)		(1.7)
Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		0.4		0.3	0.4	0.3	0.5	0.4
ASU 2018-02 Adoption								(2.7)			(2.7)
Indiana Michigan Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(10.7)			(11.5)	(12.2)		(10.7)	(11.5)		(10.7)
Change in Fair Value Recognized in AOCI		0.4				0			0.4		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0.4			1		1.5
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0.3			0.8		1.2
Net Current Period Other Comprehensive Income (Loss)		0.4				0.3			1.2		1.2
ASU 2018-02 Adoption											(2.4)
Ending Balance in AOCI		(10.3)		(10.7)		(11.9)	(12.2)		(10.3)		(11.9)
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		44.8				48.9			163.3		167.7
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]					0.4			1		1.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.2)				(0.2)			(0.6)		(0.6)
Amortization of Actuarial (Gains) Losses		0.2				0.2			0.5		0.6
Income Tax (Expense) Benefit		0				0.1			0.2		0.3
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]					0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.2)				(0.2)			(0.6)		(0.6)
Amortization of Actuarial (Gains) Losses		0.2				0.2			0.5		0.6
Income Tax (Expense) Benefit		0				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]					0.4			1		1.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0				0			0		0
Amortization of Actuarial (Gains) Losses		0				0			0		0
Income Tax (Expense) Benefit		0				0.1			0.2		0.3
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI					1				1
Interest Rate
Interest Expense		27.9				26.1			78.1		76.6
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		11.2				(28.1)			40.9		11.4
Net Current Period Other Comprehensive Income (Loss)		(0.3)		(0.4)	(0.3)	(0.4)	(0.3)	(0.3)
ASU 2018-02 Adoption								0.4
Ending Balance in AOCI		0							0
Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		(0.3)		(0.4)	(0.3)	(0.4)	(0.3)	(0.3)
ASU 2018-02 Adoption								0.4
Ohio Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0.3			1	1.7		1.9	1		1.9
Change in Fair Value Recognized in AOCI		(0.2)				0			(0.2)		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.1)				(0.5)			(1)		(1.3)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.1)				(0.4)			(0.8)		(1)
Net Current Period Other Comprehensive Income (Loss)		(0.3)				(0.4)			(1)		(1)
ASU 2018-02 Adoption											0.4
Ending Balance in AOCI		0		0.3		1.3	1.7		0		1.3
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		158.3				166.3			454		534.7
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(0.1)				(0.5)			(1)		(1.3)
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0				(0.1)			(0.2)		(0.3)
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI					2.1				2.1
Interest Rate
Interest Expense		16.1				16.4			50.3		47.4
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		6.9				3.6			7.2		8.6
Net Current Period Other Comprehensive Income (Loss)		(0.2)		(0.3)	(0.2)	(0.2)	(0.3)	(0.2)
ASU 2018-02 Adoption								0.5
Ending Balance in AOCI		1.4							1.4
Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		(0.2)		(0.3)	(0.2)	(0.2)	(0.3)	(0.2)
ASU 2018-02 Adoption								0.5
Public Service Co Of Oklahoma [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.6			2.1	2.6		2.6	2.1		2.6
Change in Fair Value Recognized in AOCI		(0.3)				0			(0.3)		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.2				(0.2)			(0.5)		(0.9)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.1				(0.2)			(0.4)		(0.7)
Net Current Period Other Comprehensive Income (Loss)		(0.2)				(0.2)			(0.7)		(0.7)
ASU 2018-02 Adoption											0.5
Ending Balance in AOCI		1.4		1.6		2.4	2.6		1.4		2.4
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		115.3				116.8			340.7		352.3
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]	0.2				(0.2)			(0.5)		(0.9)
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0.1				0			(0.1)		(0.2)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(5.2)			(5.4)	(4.7)		(4)	(5.4)		(4)
Change in Fair Value Recognized in AOCI		0.3				2.3			0.3		2.3
Interest Rate
Interest Expense		29.2				32.7			89.4		95.8
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.3)				0.1			(0.1)		0.3
Income Tax (Expense) Benefit		(0.7)				9.6			0		17.9
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.3)				0.1			(0.1)		0.3
Net Current Period Other Comprehensive Income (Loss)		0		0.1	0.1	2.4	0.1	0.1	0.2		2.6
ASU 2018-02 Adoption								(1.3)
Ending Balance in AOCI		(5.2)		(5.2)		(2.3)	(4.7)		(5.2)		(2.3)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(2.7)			(2.1)	1.7		2	(2.1)		2
Change in Fair Value Recognized in AOCI		0				0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.3)				(0.4)			(1.1)		(1.3)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.3)				(0.3)			(0.9)		(1)
Net Current Period Other Comprehensive Income (Loss)		(0.3)				(0.3)			(0.9)		(1)
ASU 2018-02 Adoption											0.4
Ending Balance in AOCI		(3)		(2.7)		1.4	1.7		(3)		1.4
Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				0.1	0.1	2.4	0.1	0.1
ASU 2018-02 Adoption								(0.9)			(0.9)
Southwestern Electric Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(2.5)			$ (3.3)	(6.4)		$ (6)	(3.3)		(6)
Change in Fair Value Recognized in AOCI		0.3				2.3			0.3		2.3
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0				0.5			1		1.6
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0				0.4			0.8		1.3
Net Current Period Other Comprehensive Income (Loss)		0.3				2.7			1.1		3.6
ASU 2018-02 Adoption											(1.3)
Ending Balance in AOCI		(2.2)		$ (2.5)		(3.7)	$ (6.4)		(2.2)		(3.7)
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		44.8				36.6			110.5		132.7
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]					0.5			1		1.6
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.5)				(0.5)			(1.5)		(1.5)
Amortization of Actuarial (Gains) Losses		0.2				0.1			0.4		0.2
Income Tax (Expense) Benefit		0				0			0		0
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]					0			0		0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.5)				(0.5)			(1.5)		(1.5)
Amortization of Actuarial (Gains) Losses		0.2				0.1			0.4		0.2
Income Tax (Expense) Benefit		0				(0.1)			(0.2)		(0.3)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]					0.5			1		1.6
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0				0			0		0
Amortization of Actuarial (Gains) Losses		0				0			0		0
Income Tax (Expense) Benefit		$ 0				$ 0.1			$ 0.2		$ 0.3
[1]	The change in fair value includes $2 million and $6 million
[2]	Amounts reclassified to the referenced line item on the statements of income.

Rate Matters Regulated Operatio

Rate Matters Regulated Operations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2019	Dec. 31, 2018
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 22,624.4	$ 21,699.9
Accumulated Depreciation and Amortization		18,760.2	17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		58,692.7	55,099.1
Materials and Supplies		613.5	579.6
Regulatory Liability, Noncurrent		8,552.8	8,540.3
Regulatory Assets, Noncurrent		3,131.4	3,310.4
Effects of Regulation Textuals [Abstract]
Secured Debt		1,059.4	1,111.4
Texas Storm Cost Securitization [Member]
Effects of Regulation Textuals [Abstract]
Secured Debt		235
Oklaunion Generating Station [Member] | Generating Units Probable of Abandonment [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		106.6
Accumulated Depreciation and Amortization		80.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		26
Oklaunion Power Station Accelerated Depreciation	[1]	21.9
Materials and Supplies		3.2
Regulatory Liability, Noncurrent		$ 5.1
Expected Retirement Date		2020
Remaining Recovery Period, Plant Depreciation		27 years
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 351.8	352.1
Accumulated Depreciation and Amortization		1,742.7	1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,587.8	7,991.8
Materials and Supplies		54.6	52.8
Regulatory Liability, Noncurrent		1,325.1	1,344.3
Regulatory Assets, Noncurrent		259.6	430
AEP Texas Inc. [Member] | Texas Storm Cost Securitization [Member]
Effects of Regulation Textuals [Abstract]
Secured Debt		235
AEP Transmission Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		368.8	271.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,898.6	7,996.2
Materials and Supplies		15.1	19
Regulatory Liability, Noncurrent		541.2	521.3
Regulatory Assets, Noncurrent		7.3	12.9
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		6,560.5	6,509.6
Accumulated Depreciation and Amortization		4,300.2	4,124.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,992.1	10,668.3
Materials and Supplies		102.1	100.1
Regulatory Liability, Noncurrent		1,336.9	1,449.7
Regulatory Assets, Noncurrent		474.2	475.8
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		5,002	4,887.2
Accumulated Depreciation and Amortization		3,280.5	3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,832.7	6,611.2
Materials and Supplies		169.9	167.3
Regulatory Liability, Noncurrent		1,809	1,574.5
Regulatory Assets, Noncurrent		490.2	512.5
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		2,256.1	2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,697.3	6,274.9
Materials and Supplies		48.5	42.9
Regulatory Liability, Noncurrent		1,143.6	1,221.2
Regulatory Assets, Noncurrent		372.2	387.5
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		1,569.9	1,577
Accumulated Depreciation and Amortization		1,558.5	1,472.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		4,038.3	3,966.7
Materials and Supplies		46.2	44.8
Regulatory Liability, Noncurrent		858.9	864.7
Regulatory Assets, Noncurrent		380.7	369
Public Service Co Of Oklahoma [Member] | Oklaunion Generating Station [Member] | Generating Units Probable of Abandonment [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		106.6
Accumulated Depreciation and Amortization		80.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		26
Oklaunion Power Station Accelerated Depreciation	[1]	21.9
Materials and Supplies		3.2
Regulatory Liability, Noncurrent		$ 5.1
Expected Retirement Date		2020
Remaining Recovery Period, Plant Depreciation		27 years
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 4,676.1	4,672.6
Accumulated Depreciation and Amortization		2,848.2	2,808.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,003.1	6,871.8
Materials and Supplies		69.8	67.5
Regulatory Liability, Noncurrent		918.1	923
Regulatory Assets, Noncurrent		223.6	230.8
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[2]	168.4	288
Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		2.3	152.6
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[2]	42.9	44.9
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		10.8	3.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.1	1
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		21.9	6
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		63	64.4
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]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		6.8	5.3
Cook Plant Study Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		10.7	0
Kentucky Deferred Purchase Power Expenses [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		26.2	14.5
Oklaunion Power Station Accelerated Depreciation [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		21.9	5.5
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]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		21.9	5.5
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		5.4	9.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.3	0.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		26.8	20.7
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	0.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.1	3.3
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]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.1	1
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	0.5
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		4.2	3.6
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		37.8	35.3
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		37.8	35.3
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		5.1	9
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		91
Effects of Regulation Textuals [Abstract]
Cost of Removal		17
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		91
Effects of Regulation Textuals [Abstract]
Cost of Removal		17
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		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]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		50.3	50.3
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1.4	4.9
Rate Case Expense [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		2.3	0.2
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[3]	0	152.4
Storm Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[3]	$ 0	$ 152.4
[1]	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” discussion below for additional information.
[2]	In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million , 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.
[3]	In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information.

Rate Matters East Companies (De

Rate Matters East Companies (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 24, 2019	Sep. 30, 2019	Dec. 31, 2018
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		$ 18,760.2	$ 17,986.1
Construction Work in Progress		5,244.5	4,393.9
AEP Transmission Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		368.8	271.9
Construction Work in Progress		1,858.4	1,578.3
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		4,300.2	4,124.4
Construction Work in Progress		667.4	490.2
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		3,280.5	3,151.6
Construction Work in Progress		516.2	465.3
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		2,256.1	2,218.6
Construction Work in Progress		$ 485.3	$ 432.1
Virginia Legislation Affecting Earnings Reviews [Member]
Public Utilities, General Disclosures [Line Items]
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 Earnings Reviews [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
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
Potential Increase to Annual Transmission Depreciation Rates		6
Virginia Staff Depreciation Study Request [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Potential Increase to Total Annual Depreciation Rates		21
Potential Increase to Annual Transmission Depreciation Rates		6
Virginia Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		40
Refund for Excess ADIT Associated with Certain Depreciable Property		9
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		94
One Time Refund of Estimated Excess Taxes Collected		22
Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		40
Refund for Excess ADIT Associated with Certain Depreciable Property		9
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		94
One Time Refund of Estimated Excess Taxes Collected		$ 22
2018 West Virginia Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		9.75%
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 24
Amount of Increase Related to Annual Depreciation Rates		32
Requested Annual Increase		$ 115
Requested Return on Equity		10.22%
Approved Amount of Increase Related to Annual Depreciation Rates		$ 18
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		14
Adjusted Annual Increase Request due to Tax Reform		95
Approved Annual Revenue Increase		$ 44
2018 West Virginia Base Rate Case [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		9.75%
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 19
Amount of Increase Related to Annual Depreciation Rates		28
Requested Annual Increase		$ 98
Requested Return on Equity		10.22%
Approved Amount of Increase Related to Annual Depreciation Rates		$ 14
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		12
Adjusted Annual Increase Request due to Tax Reform		80
Approved Annual Revenue Increase		36
Michigan Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Associated with Certain Depreciable Property		68
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		37
Michigan Tax Reform [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Associated with Certain Depreciable Property		68
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		37
2019 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Increase Related to Annual Depreciation Rates		78
Amount of Increase Related to Annual Depreciation Rates due to Proposed Investments		52
Amount of Increase Related to Annual Depreciation Rates due to Increased Depreciation Expense		26
Requested Annual Increase		$ 172
Requested Return on Equity		10.50%
2019 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Increase Related to Annual Depreciation Rates		$ 78
Amount of Increase Related to Annual Depreciation Rates due to Proposed Investments		52
Amount of Increase Related to Annual Depreciation Rates due to Increased Depreciation Expense		26
Requested Annual Increase		$ 172
Requested Return on Equity		10.50%
2019 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Increase Related to Annual Depreciation Rates		$ 19
Amount of Increase Related to Annual Depreciation Rates due to Proposed Investments		13
Amount of Increase Related to Annual Depreciation Rates due to Increased Depreciation Expense		6
Amount of Increase Related to Lost Revenue due to Michigan Electric Customer Choice Program		10
Requested Annual Increase		$ 58
Requested Return on Equity		10.50%
2019 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Increase Related to Annual Depreciation Rates		$ 19
Amount of Increase Related to Annual Depreciation Rates due to Proposed Investments		13
Amount of Increase Related to Annual Depreciation Rates due to Increased Depreciation Expense		6
Amount of Increase Related to Lost Revenue due to Michigan Electric Customer Choice Program		10
Requested Annual Increase		$ 58
Requested Return on Equity		10.50%
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Staff Calculated Overspending		$ 10
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Staff Calculated Overspending		10
2016 SEET Filing [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		58
2016 SEET Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		$ 58
FERC Transmission Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		10.99%
Intervenor Recommended Return on Common Equity		8.32%
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
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%
Subsequent Event [Member] | 2019 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Staff Recommended Annual Increase	$ 38
Staff Recommended Return on Common Equity	9.75%
Subsequent Event [Member] | 2019 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Staff Recommended Annual Increase	$ 38
Staff Recommended Return on Common Equity	9.75%
Minimum [Member] | 2019 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ 2
Intervenor Recommended Return on Common Equity		9.00%
Minimum [Member] | 2019 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ 2
Intervenor Recommended Return on Common Equity		9.00%
Minimum [Member] | Subsequent Event [Member] | 2019 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.10%
Minimum [Member] | Subsequent Event [Member] | 2019 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.10%
Maximum [Member] | 2019 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ 33
Intervenor Recommended Return on Common Equity		9.73%
Maximum [Member] | 2019 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase		$ 33
Intervenor Recommended Return on Common Equity		9.73%
Maximum [Member] | Subsequent Event [Member] | 2019 Michigan Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase	$ 28
Intervenor Recommended Return on Common Equity	9.25%
Maximum [Member] | Subsequent Event [Member] | 2019 Michigan Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Increase	$ 28
Intervenor Recommended Return on Common Equity	9.25%
Indiana Jurisdictional Meters [Member] | 2019 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		$ 41
Indiana Jurisdictional Meters [Member] | 2019 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		41
Cook Plant Study Costs [Member] | 2019 Indiana Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		11
Cook Plant Study Costs [Member] | 2019 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		$ 11

Rate Matters West Companies (De

Rate Matters West Companies (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 24, 2019	Sep. 30, 2019	Dec. 31, 2018
Public Utilities, General Disclosures [Line Items]
Secured Debt		$ 1,059.4	$ 1,111.4
Construction Work in Progress		5,244.5	4,393.9
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		978.4	836.2
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		128.8	94
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		235	$ 199.3
AEP Texas Interim Transmission and Distribution Rates [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		1,300
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		1,300
2019 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 56
Requested Return on Equity		10.50%
Refund for Excess ADIT		$ 21
Staff Recommended Annual Decrease		$ 63
Staff Recommended Return on Common Equity		9.35%
Intervenor Recommended Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 115
2019 Texas Base Rate Case [Member] | Deregulated Generation Assets and Deferred Fuel [Member]
Public Utilities, General Disclosures [Line Items]
Increase (Decrease) in Income Tax Expense (Benefit) from Tax Reform		$ 113
2019 Texas Base Rate Case [Member] | Debt [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Capital Structure		60.00%
Requested Capital Structure		55.00%
2019 Texas Base Rate Case [Member] | Equity [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Capital Structure		40.00%
Requested Capital Structure		45.00%
2019 Texas Base Rate Case [Member] | Interest [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 2
2019 Texas Base Rate Case [Member] | Newly Constructed Transmission Operations Center and Other Service Centers [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		173
2019 Texas Base Rate Case [Member] | Storm Costs Hurricane Harvey [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		94
2019 Texas Base Rate Case [Member] | Capital Incentives [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		85
2019 Texas Base Rate Case [Member] | Capitalized Cross Arms [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		36
2019 Texas Base Rate Case [Member] | Capitalized Vegetation Management Expenses[Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		26
2019 Texas Base Rate Case [Member] | Capitalized Plant Costs for Third Party Damage [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		21
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 56
Requested Return on Equity		10.50%
Refund for Excess ADIT		$ 21
Staff Recommended Annual Decrease		$ 63
Staff Recommended Return on Common Equity		9.35%
Intervenor Recommended Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 115
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Deregulated Generation Assets and Deferred Fuel [Member]
Public Utilities, General Disclosures [Line Items]
Increase (Decrease) in Income Tax Expense (Benefit) from Tax Reform		$ 113
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Debt [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Capital Structure		60.00%
Requested Capital Structure		55.00%
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Equity [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Capital Structure		40.00%
Requested Capital Structure		45.00%
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Interest [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 2
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Newly Constructed Transmission Operations Center and Other Service Centers [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		173
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Storm Costs Hurricane Harvey [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		94
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Capital Incentives [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		85
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Capitalized Cross Arms [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		36
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Capitalized Vegetation Management Expenses[Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		26
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Capitalized Plant Costs for Third Party Damage [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Disallowance		21
Texas Storm Cost Securitization [Member]
Public Utilities, General Disclosures [Line Items]
Excess ADIT		64
Secured Debt		235
Texas Restoration Carrying Costs		33
Debt Carrying Costs Recorded as Reduction to Interest Expense		21
Transmission Related Assets to be Recovered at a Later Time		95
Texas Storm Cost Securitization [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Excess ADIT		64
Secured Debt		235
Texas Restoration Carrying Costs		33
Debt Carrying Costs Recorded as Reduction to Interest Expense		21
Transmission Related Assets to be Recovered at a Later Time		$ 95
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Ownership Interest In ETT		50.00%
AEP Share Of ETT Cumulative Revenues Subject To Review		$ 987
2018 Oklahoma Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 88
Requested Return on Equity		10.30%
Amount Of Increased Depreciation Expense Requested		$ 13
Amount of Increase Related to Increased Storm Expense Amortization		7
Approved Annual Revenue Increase		$ 46
Approved Return on Common Equity		9.40%
Revenue Cap on New Distribution Reliability and Safety Rider		$ 5
2018 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 88
Requested Return on Equity		10.30%
Amount Of Increased Depreciation Expense Requested		$ 13
Amount of Increase Related to Increased Storm Expense Amortization		7
Approved Annual Revenue Increase		$ 46
Approved Return on Common Equity		9.40%
Revenue Cap on New Distribution Reliability and Safety Rider		$ 5
2012 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal Of Previously Recorded Regulatory Disallowances		114
Resulting Approved Base Rate Increase		52
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal Of Previously Recorded Regulatory Disallowances		114
Resulting Approved Base Rate Increase		52
2012 Texas Base Rate Case [Member] | Turk Generating Plant [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		$ 1,500
Texas Jurisdictional Share of Turk Plant		33.00%
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
Texas Jurisdictional Share of Turk Plant		33.00%
2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Equity		10.00%
Approved Return on Common Equity		9.60%
Requested Net Increase in Texas Annual Revenues		$ 69
Approved Net Increase in Texas Annual Revenues		50
Approved Additional Vegetation Management Expenses		2
Impairment Charge Total		19
Impairment Charge Welsh Plant, Unit 2		7
Impairment Charge Disallowed Plant Investments		12
Additional Revenues Recognized to be Surcharged to Customers		32
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management		$ 7
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Equity		10.00%
Approved Return on Common Equity		9.60%
Requested Net Increase in Texas Annual Revenues		$ 69
Approved Net Increase in Texas Annual Revenues		50
Approved Additional Vegetation Management Expenses		2
Impairment Charge Total		19
Impairment Charge Welsh Plant, Unit 2		7
Impairment Charge Disallowed Plant Investments		12
Additional Revenues Recognized to be Surcharged to Customers		32
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management		7
Louisiana 2018 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		28
Adjusted Requested Annual Increase		18
Refund for Current Year Tax Reform Rate Change		11
Additional Refund for Current Year Tax Reform Rate Change		4
Staff Recommended Annual Rate Increase		14
Louisiana 2018 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		28
Adjusted Requested Annual Increase		18
Refund for Current Year Tax Reform Rate Change		11
Additional Refund for Current Year Tax Reform Rate Change		4
Staff Recommended Annual Rate Increase		14
Welsh Plant, Units 1 And 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		612
Projected Capital Costs		550
Construction Work in Progress		399
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79
Total Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs		131
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		10
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		5
Welsh Plant, Units 1 And 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		612
Projected Capital Costs		550
Construction Work in Progress		399
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79
Total Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs		131
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		10
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		5
2019 Arkansas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 75
Requested Return on Equity		10.50%
Requested Annual Net Increase		$ 58
Requested Additional Vegetation Management Expenses		12
2019 Arkansas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 75
Requested Return on Equity		10.50%
Requested Annual Net Increase		$ 58
Requested Additional Vegetation Management Expenses		$ 12
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 Range		8.36%
Second Intervenor Recommended Return on Common Equity		8.71%
Return On Common Equity Per Settlement Agreement		10.00%
Return on Common Equity Inclusive of RTO Per Settlement Agreement		10.50%
RTO Incentive Adder Per Settlement Agreement		0.50%
Minimum [Member] | 2019 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity		9.00%
Minimum [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity		9.00%
Maximum [Member] | 2019 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Decrease Maximum		$ 159
Intervenor Recommended Return on Common Equity		9.20%
Recommended Disallowance		$ 450
Maximum [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Annual Decrease Maximum		$ 159
Intervenor Recommended Return on Common Equity		9.20%
Recommended Disallowance		$ 450
Subsequent Event [Member] | 2019 Arkansas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted Requested Annual Increase	$ 67
Settlement Agreement Annual Increase	$ 53
Settlement Agreement Return on Common Equity	9.45%
Settlement Agreement Annual Increase Net of Current Riders	$ 24
Settlement Agreement Amount of Increased Depreciation	6
Subsequent Event [Member] | 2019 Arkansas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted Requested Annual Increase	67
Settlement Agreement Annual Increase	$ 53
Settlement Agreement Return on Common Equity	9.45%
Settlement Agreement Annual Increase Net of Current Riders	$ 24
Settlement Agreement Amount of Increased Depreciation	$ 6

Commitments, Guarantees and C_3

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Jul. 25, 2019	Sep. 30, 2019
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Payments for Environmental Liabilities	$ 7.5
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		$ 204.4
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Letters of Credit Limit		1,200
Uncommitted Facility		405
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		155
Estimated Final Cost Mine Reclamation		107
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		77
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		83
Amount Collected, Rider Mine Close Other Assets Noncurrent		6
Guarantees of Equity Method Investees [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Amount of Future Payments Associated with Guarantee		75
AEP Texas Inc. [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		2.2
Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Payments for Environmental Liabilities	$ 7.5
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		3.6
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		155
Estimated Final Cost Mine Reclamation		107
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		77
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		83
Amount Collected, Rider Mine Close Other Assets Noncurrent		6
June 2022 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		$ 4,000

Acquisitions and Impairments (D

Acquisitions and Impairments (Details)	3 Months Ended				9 Months Ended
	Sep. 30, 2019USD ($)Rate	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)RateMW	Sep. 30, 2018USD ($)
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed					$ 32,400,000	$ 0
Noncash or Part Noncash Acquisition, Other Assets Acquired					0	84,000,000
Utilities Operating Expense, Operations	$ 708,300,000			$ 826,000,000	1,981,700,000	2,332,700,000
AEP Wind Holdings LLC [Member]
Acquisition		$ 134,800,000
Santa Rita East [Member]
Acquisition	118,800,000
Generation And Marketing [Member] | Racine Hydroelectric Plant [Member]
Other Asset Impairment Charges						35,000,000
Property, Plant, and Equipment, Fair Value Disclosure				0		0
Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Maximum Potential Amount of Future Payments Associated with Guarantee	186,000,000				186,000,000
Guarantor Obligations, Current Carrying Value	$ 34,000,000				$ 34,000,000
Percentage of an Asset Acquired | Rate	50.00%				50.00%
Wind Generation MWs | MW					724
Noncash or Part Noncash Acquisition, Value of Assets Acquired					$ 1,100,000,000
Payments to Acquire Businesses, Gross					583,200,000
Noncash or Part Noncash Acquisition, Debt Assumed					$ 364,000,000
Generation And Marketing [Member] | Santa Rita East [Member]
Percentage of an Asset Acquired | Rate	75.00%				75.00%
Wind Generation MWs | MW					227
Payments to Acquire Businesses, Gross					$ 356,000,000
Corporate and Other [Member] | Other Assets [Member]
Other Asset Impairment Charges			$ 21,000,000
Current Assets [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Acquisition					9,700,000
Current Liabilities [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed					12,900,000
Property, Plant and Equipment [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Acquisition					238,100,000
Asset Retirement Obligation [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed					5,700,000
Equity Method Investments [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Acquisition					405,900,000
Liabilities, Total [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed					18,600,000
Other Noncurrent Assets [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Acquisition					82,900,000
Noncontrolling Interest [Member]
Noncash or Part Noncash Acquisition, Other Assets Acquired					253,400,000
Noncontrolling Interest [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Other Assets Acquired						0
Noncontrolling Interest [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Other Assets Acquired					134,800,000
Total Assets [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Acquisition					736,600,000
Total Liabilities And Equity [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed					153,400,000
Indiana Michigan Power Co [Member]
Cost of Purchased Power from Affiliate	$ 61,000,000			60,000,000	172,100,000	181,800,000
Utilities Operating Expense, Operations	172,700,000			149,300,000	467,700,000	425,800,000
Indiana Michigan Power Co [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Cost of Purchased Power from Affiliate	2,000,000				5,000,000
Ohio Power Co [Member]
Cost of Purchased Power from Affiliate	40,600,000			39,300,000	120,400,000	97,400,000
Utilities Operating Expense, Operations	194,900,000			215,200,000	565,700,000	586,400,000
Ohio Power Co [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Cost of Purchased Power from Affiliate	3,000,000				10,000,000
Southwestern Electric Power Co [Member]
Utilities Operating Expense, Operations	91,900,000			$ 99,100,000	242,400,000	$ 292,000,000
Southwestern Electric Power Co [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Cost of Purchased Power from Affiliate	$ 3,000,000				$ 6,000,000

Benefit Plans (Details)

Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 23.8	$ 24.4	$ 71.6	$ 73.2
Interest Cost	51.1	46.9	153.3	140.8
Expected Return on Plan Assets	(74)	(72.6)	(222)	(217.7)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	14.4	21.3	43.2	63.9
Net Periodic Benefit Cost (Credit)	15.3	20	46.1	60.2
Pension Plans [Member] | AEP Texas Inc. [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.2	2.3	6.5	6.9
Interest Cost	4.4	4	13.1	12
Expected Return on Plan Assets	(6.5)	(6.4)	(19.4)	(19.2)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.2	1.8	3.7	5.4
Net Periodic Benefit Cost (Credit)	1.3	1.7	3.9	5.1
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.4	2.4	7.1	7
Interest Cost	6.3	5.8	18.9	17.6
Expected Return on Plan Assets	(9.4)	(9.1)	(28.1)	(27.4)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.8	2.6	5.3	7.9
Net Periodic Benefit Cost (Credit)	1.1	1.7	3.2	5.1
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3.3	3.4	10	10.2
Interest Cost	6	5.6	17.9	16.6
Expected Return on Plan Assets	(9.1)	(9)	(27.5)	(26.8)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.6	2.5	4.9	7.4
Net Periodic Benefit Cost (Credit)	1.8	2.5	5.3	7.4
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.9	2	5.9	5.8
Interest Cost	4.8	4.4	14.3	13.3
Expected Return on Plan Assets	(7.3)	(7.2)	(22)	(21.6)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.3	2	4	6
Net Periodic Benefit Cost (Credit)	0.7	1.2	2.2	3.5
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.6	1.7	4.9	5.3
Interest Cost	2.6	2.5	7.9	7.4
Expected Return on Plan Assets	(4)	(4)	(12.2)	(12.1)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	0.7	1.1	2.2	3.3
Net Periodic Benefit Cost (Credit)	0.9	1.3	2.8	3.9
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.1	2.4	6.4	7
Interest Cost	3.1	2.8	9.3	8.5
Expected Return on Plan Assets	(4.4)	(4.4)	(13.3)	(13.1)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	0.9	1.3	2.6	3.8
Net Periodic Benefit Cost (Credit)	1.7	2.1	5	6.2
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.4	2.9	7.1	8.7
Interest Cost	12.6	11.8	37.9	35.5
Expected Return on Plan Assets	(23.4)	(25.6)	(70.3)	(76.7)
Amortization of Prior Service Cost (Credit)	(17.3)	(17.3)	(51.8)	(51.8)
Amortization of Net Actuarial Loss	5.5	2.7	16.6	7.9
Net Periodic Benefit Cost (Credit)	(20.2)	(25.5)	(60.5)	(76.4)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.1	0.3	0.5	0.7
Interest Cost	1	0.9	3	2.8
Expected Return on Plan Assets	(1.9)	(2.1)	(5.8)	(6.4)
Amortization of Prior Service Cost (Credit)	(1.5)	(1.5)	(4.4)	(4.4)
Amortization of Net Actuarial Loss	0.5	0.2	1.4	0.6
Net Periodic Benefit Cost (Credit)	(1.8)	(2.2)	(5.3)	(6.7)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.3	0.7	0.8
Interest Cost	2.2	2.1	6.5	6.2
Expected Return on Plan Assets	(3.7)	(4)	(11)	(12)
Amortization of Prior Service Cost (Credit)	(2.5)	(2.5)	(7.5)	(7.5)
Amortization of Net Actuarial Loss	1	0.4	2.8	1.4
Net Periodic Benefit Cost (Credit)	(2.8)	(3.7)	(8.5)	(11.1)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.4	1	1.2
Interest Cost	1.5	1.4	4.4	4.1
Expected Return on Plan Assets	(2.8)	(3.1)	(8.5)	(9.3)
Amortization of Prior Service Cost (Credit)	(2.4)	(2.4)	(7.1)	(7.1)
Amortization of Net Actuarial Loss	0.7	0.3	2	0.9
Net Periodic Benefit Cost (Credit)	(2.7)	(3.4)	(8.2)	(10.2)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.6	0.7
Interest Cost	1.4	1.3	4.1	3.9
Expected Return on Plan Assets	(2.7)	(2.9)	(8.1)	(8.8)
Amortization of Prior Service Cost (Credit)	(1.8)	(1.7)	(5.2)	(5.2)
Amortization of Net Actuarial Loss	0.6	0.3	1.9	0.8
Net Periodic Benefit Cost (Credit)	(2.3)	(2.8)	(6.7)	(8.6)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.1	0.5	0.5
Interest Cost	0.7	0.6	2	1.8
Expected Return on Plan Assets	(1.3)	(1.3)	(3.9)	(4.1)
Amortization of Prior Service Cost (Credit)	(1.1)	(1.1)	(3.2)	(3.2)
Amortization of Net Actuarial Loss	0.3	0.1	0.9	0.4
Net Periodic Benefit Cost (Credit)	(1.2)	(1.6)	(3.7)	(4.6)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.6	0.7
Interest Cost	0.7	0.7	2.3	2.1
Expected Return on Plan Assets	(1.5)	(1.6)	(4.5)	(4.8)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.3)	(3.9)	(3.9)
Amortization of Net Actuarial Loss	0.4	0.2	1.1	0.5
Net Periodic Benefit Cost (Credit)	$ (1.5)	$ (1.8)	$ (4.4)	$ (5.4)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended						9 Months Ended
		Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Reportable Segment Information
Revenue from Contracts with Customers		$ 4,315			$ 4,333.1			$ 11,945.4	$ 12,394.6
Sales to AEP Affiliates		0			0			0	0
Total Revenues		4,315			4,333.1			11,945.4	12,394.6
Interest Expense		275.1			256.8			781.6	733.1
Income Tax Expense (Benefit)		40.6			(80.7)			30.7	93.5
Net Income (Loss)		733.9	$ 459.1	$ 574.1	579.7	$ 530.1	$ 456.7	1,767.1	1,566.5
Balance Sheet Information
Total Property, Plant and Equipment		77,452.9						77,452.9		$ 73,085.2
Accumulated Depreciation and Amortization		18,760.2						18,760.2		17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		58,692.7						58,692.7		55,099.1
Total Assets		73,900.7						73,900.7		68,802.8
Long-term Debt Due Within One Year		1,327.7						1,327.7		1,698.5
Long-term Debt - Affiliated		0						0		0
Long-term Debt		24,553.5						24,553.5		21,648.2
Total Long-term Debt Outstanding		25,881.2						25,881.2		23,346.7
Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,598.9			2,610.2			7,087.6	7,332.4
Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,147.3			1,180.9			3,328.7	3,450
Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		501.2			486.5			1,323.8	1,399.3
Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		67.6			55.5			205.3	212.9
AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		205.7			148.4			608	453.8
Total Revenues		259.7			194.4			770.1	586.2
Interest Income		0.8			0.5			2.1	1.3
Interest Expense		26.4			19.8			69.5	60.7
Income Tax Expense (Benefit)		30.1			17.6			90.7	63.7
Net Income (Loss)		107.6	$ 136	$ 104.3	78.1	$ 82	$ 84.1	347.9	244.2
Balance Sheet Information
Total Property, Plant and Equipment		9,267.4						9,267.4		8,268.1
Accumulated Depreciation and Amortization		368.8						368.8		271.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,898.6						8,898.6		7,996.2
Notes Receivable, Related Parties		0						0		0
Total Assets		9,352.7						9,352.7		8,394.1
Long-term Debt Due Within One Year		85						85		85
Long-term Debt		3,426.9						3,426.9		2,738
Total Long-term Debt Outstanding		3,511.9						3,511.9		2,823
AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		54			46			162.1	132.3
AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0			0			0	0.1
Reconciling Adjustments [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0			0			0	0
Sales to AEP Affiliates		(348.2)			(247.6)			(991.7)	(674.1)
Total Revenues		(348.2)			(247.6)			(991.7)	(674.1)
Net Income (Loss)		0			0			0	0
Balance Sheet Information
Total Property, Plant and Equipment	[1]	(354.5)						(354.5)		(354.6)
Accumulated Depreciation and Amortization	[1]	(186.4)						(186.4)		(186.5)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	(168.1)						(168.1)		(168.1)
Total Assets	[1],[2]	(3,737.9)						(3,737.9)		(2,714.8)
Long-term Debt Due Within One Year		0						0		0
Long-term Debt - Affiliated		(91.2)						(91.2)		(82.2)
Long-term Debt		0						0		0
Total Long-term Debt Outstanding		(91.2)						(91.2)		(82.2)
Reconciling Adjustments [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0			0			0	0
Sales to AEP Affiliates		0			0			0	0
Total Revenues		0			0			0	0
Interest Income	[3]	(31.9)			(25.7)			(88.4)	(75.3)
Interest Expense	[3]	(31.9)			(25.7)			(88.4)	(75.3)
Income Tax Expense (Benefit)		0			0			0	0
Net Income (Loss)		0			0			0	0
Balance Sheet Information
Total Property, Plant and Equipment		0						0		0
Accumulated Depreciation and Amortization		0						0		0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0						0		0
Notes Receivable, Related Parties	[4]	(3,511.9)						(3,511.9)		(2,823)
Total Assets	[5]	(3,599.8)						(3,599.8)		(2,869.8)
Total Long-term Debt Outstanding	[4]	(3,550)						(3,550)		(2,850)
Reconciling Adjustments [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0			0			0	0
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates		46.6			26.5			85	61.3
Total Revenues		2,645.5			2,636.7			7,172.6	7,393.7
Net Income (Loss)		438.4			345.6			920.8	856.3
Balance Sheet Information
Total Property, Plant and Equipment		46,739.8						46,739.8		45,365.1
Accumulated Depreciation and Amortization		14,359.3						14,359.3		13,822.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		32,380.5						32,380.5		31,542.6
Total Assets		40,746.1						40,746.1		38,874.3
Long-term Debt Due Within One Year		687.4						687.4		1,066.3
Long-term Debt - Affiliated		59						59		50
Long-term Debt		12,161.1						12,161.1		11,442.7
Total Long-term Debt Outstanding		12,907.5						12,907.5		12,559
Vertically Integrated Utilities [Member] | Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,598.9			2,610.2			7,087.6	7,332.4
Transmission And Distribution Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates		39.3			30.6			125.6	60.9
Total Revenues		1,186.6			1,211.5			3,454.3	3,510.9
Net Income (Loss)		133.7			145.2			421.6	384.6
Balance Sheet Information
Total Property, Plant and Equipment		19,283.9						19,283.9		18,126.7
Accumulated Depreciation and Amortization		3,907.3						3,907.3		3,833.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		15,376.6						15,376.6		14,293
Total Assets		17,967.6						17,967.6		17,083.4
Long-term Debt Due Within One Year		391.5						391.5		549.1
Long-term Debt - Affiliated		0						0		0
Long-term Debt		5,868.9						5,868.9		5,048.8
Total Long-term Debt Outstanding		6,260.4						6,260.4		5,597.9
Transmission And Distribution Utilities [Member] | Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,147.3			1,180.9			3,328.7	3,450
AEP Transmission Holdco [Member]
Reportable Segment Information
Sales to AEP Affiliates		207.5			135.3			611.8	408.7
Total Revenues		273			187.2			808.3	605.2
Net Income (Loss)		127			74.2			407.6	280.9
Balance Sheet Information
Total Property, Plant and Equipment		9,700.4						9,700.4		8,659.5
Accumulated Depreciation and Amortization		383.8						383.8		282.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,316.6						9,316.6		8,376.7
Total Assets		10,606.7						10,606.7		9,543.7
Long-term Debt Due Within One Year		249						249		85
Long-term Debt - Affiliated		0						0		0
Long-term Debt		3,426.9						3,426.9		2,888.6
Total Long-term Debt Outstanding		3,675.9						3,675.9		2,973.6
AEP Transmission Holdco [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		65.5			51.9			196.5	196.5
Generation And Marketing [Member]
Reportable Segment Information
Sales to AEP Affiliates		32.5			35.1			104.4	88.1
Total Revenues		533.7			521.6			1,428.2	1,487.4
Net Income (Loss)		88.7			5.1			133.1	61.8
Balance Sheet Information
Total Property, Plant and Equipment		1,661.6						1,661.6		893.3
Accumulated Depreciation and Amortization		99.8						99.8		47
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		1,561.8						1,561.8		846.3
Total Assets		3,315.9						3,315.9		1,979.7
Long-term Debt Due Within One Year		0						0		0.1
Long-term Debt - Affiliated		32.2						32.2		32.2
Long-term Debt		(0.3)						(0.3)		(0.3)
Total Long-term Debt Outstanding		31.9						31.9		32
Generation And Marketing [Member] | Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		501.2			486.5			1,323.8	1,399.3
All Other [Member]
Reportable Segment Information
Sales to AEP Affiliates	[6]	22.3			20.1			64.9	55.1
Total Revenues	[6]	24.4			23.7			73.7	71.5
Net Income (Loss)	[6]	(53.9)			9.6			(116)	(17.1)
Balance Sheet Information
Total Property, Plant and Equipment	[6]	421.7						421.7		395.2
Accumulated Depreciation and Amortization	[6]	196.4						196.4		186.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[6]	225.3						225.3		208.6
Total Assets	[6],[7]	5,002.3						5,002.3		4,036.5
Long-term Debt Due Within One Year	[6],[8]	(0.2)						(0.2)		(2)
Long-term Debt - Affiliated	[6]	0						0		0
Long-term Debt	[6]	3,096.9						3,096.9		2,268.4
Total Long-term Debt Outstanding	[6],[8]	3,096.7						3,096.7		2,266.4
All Other [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers	[6]	2.1			3.6			8.8	16.4
State Transcos [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		205.7			148.4			608	453.8
Total Revenues		259.7			194.4			770.1	586.2
Interest Income		0.4			0.2			0.8	0.4
Interest Expense		26.4			19.8			69.5	60.7
Income Tax Expense (Benefit)		30			18.4			90.5	63.7
Net Income (Loss)		107.3			77.1			347.1	243.6
Balance Sheet Information
Total Property, Plant and Equipment		9,267.4						9,267.4		8,268.1
Accumulated Depreciation and Amortization		368.8						368.8		271.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,898.6						8,898.6		7,996.2
Notes Receivable, Related Parties		0						0		0
Total Assets		9,363.5						9,363.5		8,406.8
Total Long-term Debt Outstanding		3,550						3,550		2,850
State Transcos [Member] | AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		54			46			162.1	132.3
State Transcos [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0			0			0	0.1
AEPTCo Parent [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		0			0			0	0
Total Revenues		0			0			0	0
Interest Income		32.3			26			89.7	76.2
Interest Expense		31.9			25.7			88.4	75.3
Income Tax Expense (Benefit)		0.1			(0.8)			0.2	0
Net Income (Loss)	[9]	0.3			1			0.8	0.6
Balance Sheet Information
Total Property, Plant and Equipment		0						0		0
Accumulated Depreciation and Amortization		0						0		0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0						0		0
Notes Receivable, Related Parties		3,511.9						3,511.9		2,823
Total Assets	[10]	3,589						3,589		2,857.1
Total Long-term Debt Outstanding		3,511.9						3,511.9		$ 2,823
AEPTCo Parent [Member] | AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0			0			0	0
AEPTCo Parent [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		$ 0			$ 0			$ 0	$ 0
[1]	Includes eliminations due to an intercompany finance lease.
[2]	Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
[3]	Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
[4]	Elimination of intercompany debt.
[5]	Primarily relates to the elimination of Notes Receivable from the State Transcos.
[6]	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.
[7]	Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
[8]	Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.
[9]	Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
[10]	Includes the elimination of AEPTCo Parent’s investments in State Transcos.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, MWh in Millions, MMBTU in Millions		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2019USD ($)MWhMMBTUgal		Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)MWhMMBTUgal		Sep. 30, 2018USD ($)	Dec. 31, 2018USD ($)MWhMMBTUgal
Interest Expense		$ 275,100,000		$ 256,800,000	$ 781,600,000		$ 733,100,000
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			$ 18,000,000
Cash Collateral Paid Netted Against Risk Management Liabilities		21,000,000			21,000,000			4,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		186,700,000			186,700,000			162,800,000
Long-term Risk Management Assets		299,000,000			299,000,000			254,000,000
Total Assets		485,700,000			485,700,000			416,800,000
Current Risk Management Liabilities		75,300,000			75,300,000			55,000,000
Long-term Risk Management Liabilities		298,600,000			298,600,000			263,400,000
Total Liabilities		373,900,000			373,900,000			318,400,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		43,100,000		39,800,000	73,700,000		268,800,000
Carrying Amount of Hedged Asset (Liability)	[1]	(521,200,000)			(521,200,000)			(478,300,000)
Cumulative Fair Value Hedging Adjustment in the Carrying Amount of the Hedged Asset (Liability)	[1]	(25,100,000)			(25,100,000)			17,400,000
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments	[2]	13,200,000		(6,300,000)	42,500,000		(28,100,000)
Gain (Loss) on Fair Value Portion of Long Term Debt	[2]	(13,200,000)		6,300,000	(42,500,000)		28,100,000
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		261,000,000			261,000,000			225,500,000
Amount of Cash Collateral Posted		3,400,000			3,400,000			1,800,000
Additional Settlement Liability if Cross Default Provision is Triggered		230,700,000			230,700,000			181,000,000
AEP Texas Inc. [Member]
Interest Expense		35,800,000		37,300,000	92,700,000		108,900,000
Fair Value of Derivative Instruments
Current Risk Management Liabilities		300,000			300,000			200,000
Long-term Risk Management Liabilities		100,000			100,000			0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(200,000)		200,000	100,000		600,000
AEP Transmission Co [Member]
Interest Expense		26,400,000		19,800,000	69,500,000		60,700,000
Appalachian Power Co [Member]
Interest Expense		51,600,000		50,800,000	152,500,000		146,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		56,500,000			56,500,000			57,200,000
Long-term Risk Management Assets		200,000			200,000			900,000
Current Risk Management Liabilities		1,100,000			1,100,000			400,000
Long-term Risk Management Liabilities		300,000			300,000			200,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		10,600,000		24,000,000	(3,500,000)		133,800,000
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		3,900,000			3,900,000			900,000
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		200,000			200,000			0
Indiana Michigan Power Co [Member]
Interest Expense		28,800,000		34,500,000	85,900,000		95,600,000
Fair Value of Derivative Instruments
Current Risk Management Assets		10,500,000			10,500,000			8,600,000
Long-term Risk Management Assets		100,000			100,000			600,000
Current Risk Management Liabilities		200,000			200,000			300,000
Long-term Risk Management Liabilities		0			0			100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		3,200,000		(3,400,000)	17,800,000		4,800,000
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		2,300,000			2,300,000			500,000
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		100,000			100,000			0
Ohio Power Co [Member]
Interest Expense		27,900,000		26,100,000	78,100,000		76,600,000
Fair Value of Derivative Instruments
Current Risk Management Liabilities		7,200,000			7,200,000			5,800,000
Long-term Risk Management Liabilities		105,700,000			105,700,000			93,800,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(2,700,000)		(9,100,000)	(20,100,000)		33,000,000
Public Service Co Of Oklahoma [Member]
Interest Expense		16,100,000		16,400,000	50,300,000		47,400,000
Fair Value of Derivative Instruments
Current Risk Management Assets		21,700,000			21,700,000			10,400,000
Current Risk Management Liabilities		300,000			300,000			1,000,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		4,100,000		3,500,000	27,400,000		34,600,000
Southwestern Electric Power Co [Member]
Interest Expense		29,200,000		32,700,000	89,400,000		95,800,000
Fair Value of Derivative Instruments
Current Risk Management Assets		9,400,000			9,400,000			4,800,000
Current Risk Management Liabilities		1,700,000			1,700,000			400,000
Long-term Risk Management Liabilities		3,000,000			3,000,000			2,200,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2,900,000		1,100,000	22,400,000		6,400,000
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		4,700,000			4,700,000			2,300,000
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		2,800,000			2,800,000			2,300,000
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[3]	446,200,000	[4]		446,200,000	[4]		382,700,000	[5]
Total Liabilities	[3]	264,100,000	[4]		264,100,000	[4]		242,100,000	[5]
Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Total Liabilities	[3]	400,000			400,000			200,000
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	56,700,000			56,700,000			58,100,000
Total Liabilities	[3],[6]	1,400,000			1,400,000			600,000
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	10,600,000			10,600,000			9,200,000
Total Liabilities	[3],[6]	200,000			200,000			400,000
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Liabilities	[3],[6]	112,900,000			112,900,000			99,600,000
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	21,700,000			21,700,000			10,400,000
Total Liabilities	[3],[6]	300,000			300,000			1,000,000
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	9,400,000			9,400,000			4,800,000
Total Liabilities	[3],[6]	4,700,000			4,700,000			2,600,000
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(82,200,000)			(82,200,000)			(23,000,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					$ (24,200,000)			10,400,000
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows					123 months
Cross Default Provisions Maximum Third Party Obligation Amount		50,000,000			$ 50,000,000			50,000,000
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	337,000,000			337,000,000			397,500,000
Long-term Risk Management Assets	[7]	319,000,000			319,000,000			276,400,000
Total Assets	[7]	656,000,000			656,000,000			673,900,000
Current Risk Management Liabilities	[7]	213,400,000			213,400,000			293,800,000
Long-term Risk Management Liabilities	[7]	281,700,000			281,700,000			225,700,000
Total Liabilities	[7]	495,100,000			495,100,000			519,500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	160,900,000			160,900,000			154,400,000
Commodity [Member] | Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0			0			0
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	0			0			0
Current Risk Management Liabilities	[7]	400,000			400,000			700,000
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	400,000			400,000			700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(400,000)			(400,000)			(700,000)
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	86,300,000			86,300,000			114,400,000
Long-term Risk Management Assets	[7]	4,100,000			4,100,000			3,100,000
Total Assets	[7]	90,400,000			90,400,000			117,500,000
Current Risk Management Liabilities	[7]	32,300,000			32,300,000			56,700,000
Long-term Risk Management Liabilities	[7]	4,400,000			4,400,000			2,400,000
Total Liabilities	[7]	36,700,000			36,700,000			59,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	53,700,000			53,700,000			58,400,000
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	30,500,000			30,500,000			50,400,000
Long-term Risk Management Assets	[7]	2,700,000			2,700,000			2,000,000
Total Assets	[7]	33,200,000			33,200,000			52,400,000
Current Risk Management Liabilities	[7]	21,000,000			21,000,000			41,100,000
Long-term Risk Management Liabilities	[7]	2,700,000			2,700,000			1,600,000
Total Liabilities	[7]	23,700,000			23,700,000			42,700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	9,500,000			9,500,000			9,700,000
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0			0			0
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	0			0			0
Current Risk Management Liabilities	[7]	7,200,000			7,200,000			6,400,000
Long-term Risk Management Liabilities	[7]	105,700,000			105,700,000			93,800,000
Total Liabilities	[7]	112,900,000			112,900,000			100,200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(112,900,000)			(112,900,000)			(100,200,000)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	21,900,000			21,900,000			10,900,000
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	21,900,000			21,900,000			10,900,000
Current Risk Management Liabilities	[7]	500,000			500,000			1,700,000
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	500,000			500,000			1,700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	21,400,000			21,400,000			9,200,000
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	9,800,000			9,800,000			5,600,000
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	9,800,000			9,800,000			5,600,000
Current Risk Management Liabilities	[7]	2,100,000			2,100,000			1,500,000
Long-term Risk Management Liabilities	[7]	3,000,000			3,000,000			2,200,000
Total Liabilities	[7]	5,100,000			5,100,000			3,700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	4,700,000			4,700,000			1,900,000
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	16,500,000			16,500,000			28,500,000
Long-term Risk Management Assets	[7]	10,000,000			10,000,000			16,000,000
Total Assets	[7]	26,500,000			26,500,000			44,500,000
Current Risk Management Liabilities	[7]	36,400,000			36,400,000			13,200,000
Long-term Risk Management Liabilities	[7]	87,400,000			87,400,000			56,100,000
Total Liabilities	[7]	123,800,000			123,800,000			69,300,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(97,300,000)			(97,300,000)			(24,800,000)
Interest Rate [Member]
Commodity:
Derivative, Notional Amount		600,000,000			600,000,000			500,000,000
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(16,700,000)	[8]		(16,700,000)	[8]		(12,600,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					$ (3,700,000)			(1,100,000)
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows					135 months
Interest Rate [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Notional Amount		0			$ 0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(3,600,000)			(3,600,000)			(4,400,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,100,000)			(1,100,000)
Interest Rate [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		1,100,000			1,100,000			1,800,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					900,000			900,000
Interest Rate [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(10,300,000)			(10,300,000)			(11,500,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,600,000)			(1,600,000)
Interest Rate [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		0			0			1,000,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0			1,000,000
Interest Rate [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		1,400,000			1,400,000			2,100,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					1,000,000			1,000,000
Interest Rate [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(2,200,000)			(2,200,000)			(3,300,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,500,000)			(1,500,000)
Interest Rate [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	1,900,000			1,900,000			0
Long-term Risk Management Assets	[7]	25,300,000			25,300,000			0
Total Assets	[7]	27,200,000			27,200,000			0
Current Risk Management Liabilities	[7]	200,000			200,000			2,000,000
Long-term Risk Management Liabilities	[7]	0			0			15,400,000
Total Liabilities	[7]	200,000			200,000			17,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	27,000,000			27,000,000			(17,400,000)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		355,400,000			355,400,000			426,000,000
Long-term Risk Management Assets		354,300,000			354,300,000			292,400,000
Total Assets		709,700,000			709,700,000			718,400,000
Current Risk Management Liabilities		250,000,000			250,000,000			309,000,000
Long-term Risk Management Liabilities		369,100,000			369,100,000			297,200,000
Total Liabilities		619,100,000			619,100,000			606,200,000
Total MTM Derivative Contract Net Assets (Liabilities)		90,600,000			90,600,000			112,200,000
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(168,700,000)			(168,700,000)			(263,200,000)
Long-term Risk Management Assets	[9]	(55,300,000)			(55,300,000)			(38,400,000)
Total Assets	[9]	(224,000,000)			(224,000,000)			(301,600,000)
Current Risk Management Liabilities	[9]	(174,700,000)			(174,700,000)			(254,000,000)
Long-term Risk Management Liabilities	[9]	(70,500,000)			(70,500,000)			(33,800,000)
Total Liabilities	[9]	(245,200,000)			(245,200,000)			(287,800,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	21,200,000			21,200,000			(13,800,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	0			0			0
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	0			0			0
Current Risk Management Liabilities	[9]	(100,000)			(100,000)			(500,000)
Long-term Risk Management Liabilities	[9]	100,000			100,000			0
Total Liabilities	[9]	0			0			(500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	0			0			500,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(29,800,000)			(29,800,000)			(57,200,000)
Long-term Risk Management Assets	[9]	(3,900,000)			(3,900,000)			(2,200,000)
Total Assets	[9]	(33,700,000)			(33,700,000)			(59,400,000)
Current Risk Management Liabilities	[9]	(31,200,000)			(31,200,000)			(56,300,000)
Long-term Risk Management Liabilities	[9]	(4,100,000)			(4,100,000)			(2,200,000)
Total Liabilities	[9]	(35,300,000)			(35,300,000)			(58,500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	1,600,000			1,600,000			(900,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(20,000,000)			(20,000,000)			(41,800,000)
Long-term Risk Management Assets	[9]	(2,600,000)			(2,600,000)			(1,400,000)
Total Assets	[9]	(22,600,000)			(22,600,000)			(43,200,000)
Current Risk Management Liabilities	[9]	(20,800,000)			(20,800,000)			(40,800,000)
Long-term Risk Management Liabilities	[9]	(2,700,000)			(2,700,000)			(1,500,000)
Total Liabilities	[9]	(23,500,000)			(23,500,000)			(42,300,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	900,000			900,000			(900,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	0			0			0
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	0			0			0
Current Risk Management Liabilities	[9]	0			0			(600,000)
Long-term Risk Management Liabilities	[9]	0			0			0
Total Liabilities	[9]	0			0			(600,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	0			0			600,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(200,000)			(200,000)			(500,000)
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	(200,000)			(200,000)			(500,000)
Current Risk Management Liabilities	[9]	(200,000)			(200,000)			(700,000)
Long-term Risk Management Liabilities	[9]	0			0			0
Total Liabilities	[9]	(200,000)			(200,000)			(700,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	0			0			200,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(400,000)			(400,000)			(800,000)
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	(400,000)			(400,000)			(800,000)
Current Risk Management Liabilities	[9]	(400,000)			(400,000)			(1,100,000)
Long-term Risk Management Liabilities	[9]	0			0			0
Total Liabilities	[9]	(400,000)			(400,000)			(1,100,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	0			0			300,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	186,700,000			186,700,000			162,800,000
Long-term Risk Management Assets	[10]	299,000,000			299,000,000			254,000,000
Total Assets	[10]	485,700,000			485,700,000			416,800,000
Current Risk Management Liabilities	[10]	75,300,000			75,300,000			55,000,000
Long-term Risk Management Liabilities	[10]	298,600,000			298,600,000			263,400,000
Total Liabilities	[10]	373,900,000			373,900,000			318,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	111,800,000			111,800,000			98,400,000
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	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	300,000			300,000			200,000
Long-term Risk Management Liabilities	[10]	100,000			100,000			0
Total Liabilities	[10]	400,000			400,000			200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	(400,000)			(400,000)			(200,000)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	56,500,000			56,500,000			57,200,000
Long-term Risk Management Assets	[10]	200,000			200,000			900,000
Total Assets	[10]	56,700,000			56,700,000			58,100,000
Current Risk Management Liabilities	[10]	1,100,000			1,100,000			400,000
Long-term Risk Management Liabilities	[10]	300,000			300,000			200,000
Total Liabilities	[10]	1,400,000			1,400,000			600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	55,300,000			55,300,000			57,500,000
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	[10]	10,500,000			10,500,000			8,600,000
Long-term Risk Management Assets	[10]	100,000			100,000			600,000
Total Assets	[10]	10,600,000			10,600,000			9,200,000
Current Risk Management Liabilities	[10]	200,000			200,000			300,000
Long-term Risk Management Liabilities	[10]	0			0			100,000
Total Liabilities	[10]	200,000			200,000			400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	10,400,000			10,400,000			8,800,000
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	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	7,200,000			7,200,000			5,800,000
Long-term Risk Management Liabilities	[10]	105,700,000			105,700,000			93,800,000
Total Liabilities	[10]	112,900,000			112,900,000			99,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	(112,900,000)			(112,900,000)			(99,600,000)
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	[10]	21,700,000			21,700,000			10,400,000
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	21,700,000			21,700,000			10,400,000
Current Risk Management Liabilities	[10]	300,000			300,000			1,000,000
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	300,000			300,000			1,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	21,400,000			21,400,000			9,400,000
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	[10]	9,400,000			9,400,000			4,800,000
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	9,400,000			9,400,000			4,800,000
Current Risk Management Liabilities	[10]	1,700,000			1,700,000			400,000
Long-term Risk Management Liabilities	[10]	3,000,000			3,000,000			2,200,000
Total Liabilities	[10]	4,700,000			4,700,000			2,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	$ 4,700,000			$ 4,700,000			$ 2,200,000
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		424.3			424.3			371.1
Power [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		0			0			0
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		94.7			94.7			66.4
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		37.1			37.1			40.9
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		7.3			7.3			7.8
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		21.6			21.6			15.2
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		6.9			6.9			4.5
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		53.2			53.2			87.9
Natural Gas [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			4
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			2.3
Natural Gas [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		12.5			12.5			15.2
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		8.4			8.4			7.4
Heating Oil and Gasoline [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.8			1.8			1.5
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.6			1.6			1.4
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.8			0.8			0.7
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		2			2			1.8
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.8			0.8			0.7
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.9			0.9			0.8
Interest Rate Contract [Member]
Commodity:
Derivative, Notional Amount		$ 140,100,000			$ 140,100,000			$ 37,700,000
Interest Rate Contract [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			$ 0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		500,000		(700,000)	1,000,000		(9,400,000)
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		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		0
Vertically Integrated Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		21,000,000		19,300,000	27,200,000		31,700,000
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		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		0
Generation and Marketing Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | 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		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		200,000		(500,000)	200,000		(1,300,000)
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		200,000		(100,000)	500,000		(7,800,000)
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	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	100,000		100,000
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		400,000		300,000	1,600,000		8,300,000
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		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		300,000		300,000	1,400,000		7,300,000
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		0		0	100,000		800,000
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		0
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		500,000	(600,000)		1,300,000
Other Operation Expense [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		100,000	(100,000)		300,000
Other Operation Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		100,000	(100,000)		200,000
Other Operation Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		100,000	(100,000)		200,000
Other Operation Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		100,000	(200,000)		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		(100,000)		100,000	(100,000)		200,000
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		0		100,000	(100,000)		200,000
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(200,000)		600,000	(600,000)		1,500,000
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		0		100,000	(100,000)		300,000
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		0		100,000	(100,000)		300,000
Maintenance Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		100,000	(100,000)		200,000
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		0		100,000	(100,000)		300,000
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		0		100,000	0		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		0		100,000	(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	[11]	(4,800,000)		(14,000,000)	(19,400,000)		29,200,000
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	[11]	(200,000)		0	300,000		0
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	[11]	200,000		0	400,000		0
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	[11]	0		(3,500,000)	200,000		(300,000)
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	[11]	(2,600,000)		(9,300,000)	(19,800,000)		31,800,000
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	[11]	(100,000)		(600,000)	900,000		(600,000)
Regulatory Assets [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[11]	(1,600,000)		(600,000)	(400,000)		(1,700,000)
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[11]	26,300,000		33,800,000	64,500,000		206,200,000
Regulatory Liabilities [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[11]	0		0	0		0
Regulatory Liabilities [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[11]	10,000,000		24,000,000	(5,300,000)		127,300,000
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	[11]	3,200,000		0	17,200,000		11,700,000
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	[11]	0		0	0		600,000
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	[11]	4,300,000		3,900,000	26,600,000		34,800,000
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	[11]	4,500,000		1,500,000	22,900,000		7,600,000
Reclassification out of Accumulated Other Comprehensive Income [Member]
Interest Expense	[12]			400,000	500,000		900,000
Reclassification out of Accumulated Other Comprehensive Income [Member] | AEP Texas Inc. [Member]
Interest Expense	[12]			400,000	600,000		1,000,000
Reclassification out of Accumulated Other Comprehensive Income [Member] | Appalachian Power Co [Member]
Interest Expense	[12]			(400,000)	(500,000)		(900,000)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Indiana Michigan Power Co [Member]
Interest Expense	[12]			400,000	1,000,000		1,500,000
Reclassification out of Accumulated Other Comprehensive Income [Member] | Southwestern Electric Power Co [Member]
Interest Expense	[12]			500,000	1,000,000		1,600,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Commodity [Member]
Interest Expense	[12]			0	0		0
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Appalachian Power Co [Member]
Interest Expense	[12]						0
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member]
Interest Expense	[12]			400,000	500,000		900,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | AEP Texas Inc. [Member]
Interest Expense	[12]			400,000	600,000		1,000,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Appalachian Power Co [Member]
Interest Expense	[12]			(400,000)	(500,000)		(900,000)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Indiana Michigan Power Co [Member]
Interest Expense	[12]			400,000	1,000,000		1,500,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Ohio Power Co [Member]
Interest Expense	[12]	(100,000)		(500,000)	(1,000,000)		(1,300,000)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Public Service Co Of Oklahoma [Member]
Interest Expense	[12]	$ 200,000		(200,000)	(500,000)		(900,000)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Southwestern Electric Power Co [Member]
Interest Expense	[12]			$ 500,000	1,000,000		$ 1,600,000
Apple Blossom and Black Oak [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate [Member]
Interest Expense					$ 6,000,000
[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 September 30, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2019, $(8) million in periods 2020-2022 and $(1) million in periods 2025-2032; Level 3 matures $40 million in 2019, $114 million in periods 2020-2022, $26 million in periods 2023-2024 and $(4) million in periods 2025-2032. Risk management commodity contracts are substantially comprised of power contracts.
[5]	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.
[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]	Includes $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information.
[9]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[10]	All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
[11]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
[12]	Amounts reclassified to the referenced line item on the statements of income.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2019		Sep. 30, 2018	Dec. 31, 2018
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 25,881.2			$ 25,881.2			$ 23,346.7
Long Term Debt, Fair Value		29,729.1	[1]		29,729.1	[1]		24,093.9
Other Temporary Investments
Cost		322			322			355
Gross Unrealized Gains		17.6			17.6			16.4
Gross Unrealized Losses		(0.2)			(0.2)			(2.3)
Other Short-term Investments		339.4			339.4			369.1
Debt and Equity Securities Within Other Temporary Investments
Proceeds from Investment Sales		2.8		$ 0	2.8		$ 0
Purchases of Investments		26.9		0.8	35.8		2.2
Gross Realized Gains on Investment Sales		0		0	0		0
Gross Realized Losses on Investment Sales		0		0	0		0
Nuclear Trust Fund Investments
Fair Value		2,835.2			2,835.2			2,474.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,835.2			2,835.2			2,474.9
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities					1,000			784
Nuclear Trust Fund Investments
Gross Unrealized Gains					1,112.3			794.7
Other-Than-Temporary Impairments					(7.7)			(9.2)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		671.9		513.1	871.4		1,550.9
Purchases of Investments		689.1		521.2	915.7		1,589
Gross Realized Gains on Investment Sales		10.9		3.9	26.6		27.7
Gross Realized Losses on Investment Sales		7.1		3.5	15.1		22.2
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		334.9			334.9
After 1 year through 5 years		390.9			390.9
After 5 years through 10 years		199.2			199.2
After 10 years		198.5			198.5
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000			1,000			1,000
Adjusted Cost of Domestic Equity Securities		657			657			629
Unrealized Loss on Securities					9			18
Cash [Member]
Other Temporary Investments
Cost	[2]	160.1			160.1			230.6
Gross Unrealized Gains	[2]	0			0			0
Gross Unrealized Losses	[2]	0			0			0
Other Short-term Investments	[2],[3]	160.1			160.1			230.6
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,123.5			1,123.5			1,057.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,123.5			1,123.5			1,057.1
Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					74.6			28.4
Other-Than-Temporary Impairments					(7.7)			(9.2)
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[4]	133.4			133.4			106.6
Gross Unrealized Gains	[4]	0			0			0
Gross Unrealized Losses	[4]	(0.2)			(0.2)			(2.3)
Other Short-term Investments	[4]	133.2			133.2			104.3
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,694.3			1,694.3			1,395.3
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,694.3			1,694.3			1,395.3
Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains	[6]				1,037.7			766.3
Other-Than-Temporary Impairments	[6]				0			0
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		28.5			28.5			17.8
Gross Unrealized Gains		17.6			17.6			16.4
Gross Unrealized Losses		0			0			0
Other Short-term Investments	[5]	46.1			46.1			34.2
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	17.4			17.4			22.5
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	17.4			17.4			22.5
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
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		1,047.4			1,047.4			996.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,047.4			1,047.4			996.1
US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					67.8			26.7
Other-Than-Temporary Impairments					(5.8)			(7.1)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		68.6			68.6			52.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		68.6			68.6			52.4
Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					6.1			1.1
Other-Than-Temporary Impairments					(1.7)			(1.9)
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		7.5			7.5			8.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		7.5			7.5			8.6
State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					0.7			0.6
Other-Than-Temporary Impairments					(0.2)			(0.2)
AEP Texas Inc. [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,146.5			4,146.5			3,881.3
Long Term Debt, Fair Value		4,631.5			4,631.5			3,964.6
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,511.9			3,511.9			2,823
Long Term Debt, Fair Value		3,984.9			3,984.9			2,782.4
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,362.9			4,362.9			4,062.6
Long Term Debt, Fair Value		5,370.2			5,370.2			4,473.3
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,031.5			3,031.5			3,035.4
Long Term Debt, Fair Value		3,497.3			3,497.3			3,070.2
Nuclear Trust Fund Investments
Fair Value		2,835.2			2,835.2			2,474.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,835.2			2,835.2			2,474.9
Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities					1,000			784
Nuclear Trust Fund Investments
Gross Unrealized Gains					1,112.3			794.7
Other-Than-Temporary Impairments					(7.7)			(9.2)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		671.9		513.1	871.4		1,550.9
Purchases of Investments		689.1		521.2	915.7		1,589
Gross Realized Gains on Investment Sales		10.9		3.9	26.6		27.7
Gross Realized Losses on Investment Sales		7.1		$ 3.5	15.1		$ 22.2
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		334.9			334.9
After 1 year through 5 years		390.9			390.9
After 5 years through 10 years		199.2			199.2
After 10 years		198.5			198.5
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000			1,000			1,000
Adjusted Cost of Domestic Equity Securities		657			657			629
Unrealized Loss on Securities					9			18
Indiana Michigan Power Co [Member] | Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,123.5			1,123.5			1,057.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,123.5			1,123.5			1,057.1
Indiana Michigan Power Co [Member] | Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					74.6			28.4
Other-Than-Temporary Impairments					(7.7)			(9.2)
Indiana Michigan Power Co [Member] | Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,694.3			1,694.3			1,395.3
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,694.3			1,694.3			1,395.3
Indiana Michigan Power Co [Member] | Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains	[6]				1,037.7			766.3
Other-Than-Temporary Impairments	[6]				0			0
Indiana Michigan Power Co [Member] | Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	17.4			17.4			22.5
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	17.4			17.4			22.5
Indiana Michigan Power Co [Member] | 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
Indiana Michigan Power Co [Member] | US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		1,047.4			1,047.4			996.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,047.4			1,047.4			996.1
Indiana Michigan Power Co [Member] | US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					67.8			26.7
Other-Than-Temporary Impairments					(5.8)			(7.1)
Indiana Michigan Power Co [Member] | Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		68.6			68.6			52.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		68.6			68.6			52.4
Indiana Michigan Power Co [Member] | Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					6.1			1.1
Other-Than-Temporary Impairments					(1.7)			(1.9)
Indiana Michigan Power Co [Member] | State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		7.5			7.5			8.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		7.5			7.5			8.6
Indiana Michigan Power Co [Member] | State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains					0.7			0.6
Other-Than-Temporary Impairments					(0.2)			(0.2)
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,113.9			2,113.9			1,716.6
Long Term Debt, Fair Value		2,618.5			2,618.5			1,919.7
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,386.4			1,386.4			1,287
Long Term Debt, Fair Value		1,632.9			1,632.9			1,361.9
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,656.9			2,656.9			2,713.4
Long Term Debt, Fair Value		2,983			2,983			$ 2,670.2
Equity Units [Member]
Book Values and Fair Values of Long - term Debt
Long Term Debt, Fair Value		$ 887			$ 887
[1]	The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $887 million as of September 30, 2019 . See “Equity Units” section of Note 13 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 $1 billion and $784 million and unrealized losses of $9 million and $18 million as of September 30, 2019 and December 31, 2018 , respectively. 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 Assets and Liabiliti

Fair Value Assets and Liabilities (Details) - USD ($)		3 Months Ended			9 Months Ended
		Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2019		Sep. 30, 2018	Dec. 31, 2018
Assets, Fair Value Disclosure
Other Short-term Investments		$ 339,400,000			$ 339,400,000			$ 369,100,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,835,200,000			2,835,200,000			2,474,900,000
Total Assets		3,660,300,000			3,660,300,000			3,260,800,000
Risk Management Assets
Risk Management Assets		485,700,000			485,700,000			416,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		373,900,000			373,900,000			318,400,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		112,700,000		$ 172,300,000	131,200,000		$ 40,300,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	30,200,000		19,900,000	14,600,000		150,900,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	2,900,000		1,500,000	32,900,000		9,500,000
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)		22,100,000		10,400,000	(42,800,000)		16,400,000
Settlements		(67,400,000)		(56,000,000)	(114,600,000)		(212,300,000)
Transfers into Level 3	[3],[4]	3,500,000		2,300,000	400,000		16,500,000
Transfers out of Level 3	[4]	6,600,000		(1,200,000)	1,400,000		(2,500,000)
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	(300,000)		12,000,000	87,200,000		142,400,000
Ending Balance		110,300,000		161,200,000	110,300,000		161,200,000
Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		7,200,000			7,200,000			9,100,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8,000,000			8,000,000			10,200,000
Total Assets		(188,300,000)			(188,300,000)			(271,900,000)
Risk Management Assets
Risk Management Assets		(203,500,000)			(203,500,000)			(291,200,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(224,700,000)			(224,700,000)			(277,400,000)
Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		332,200,000			332,200,000			360,000,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,703,700,000			1,703,700,000			1,407,600,000
Total Assets		2,041,500,000			2,041,500,000			1,771,400,000
Risk Management Assets
Risk Management Assets		5,600,000			5,600,000			3,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,100,000			5,100,000			4,200,000
Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,500,000			1,123,500,000			1,057,100,000
Total Assets		1,396,500,000			1,396,500,000			1,407,700,000
Risk Management Assets
Risk Management Assets		273,000,000			273,000,000			350,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		293,200,000			293,200,000			369,200,000
Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Total Assets		410,600,000			410,600,000			353,600,000
Risk Management Assets
Risk Management Assets		410,600,000			410,600,000			353,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		300,300,000			300,300,000			222,400,000
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		(6,000,000)			(6,000,000)			(4,000,000)
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		40,000,000			40,000,000			108,000,000
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		(8,000,000)			(8,000,000)			1,000,000
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		114,000,000			114,000,000			37,000,000
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								1,000,000
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		26,000,000			26,000,000			23,000,000
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		(1,000,000)			(1,000,000)			1,000,000
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		(4,000,000)			(4,000,000)			(12,000,000)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6]	446,200,000	[7]		446,200,000	[7]		382,700,000	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	264,100,000	[7]		264,100,000	[7]		242,100,000	[8]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6]	(195,300,000)	[7]		(195,300,000)	[7]		(288,500,000)	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	(216,500,000)	[7]		(216,500,000)	[7]		(274,700,000)	[8]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6]	5,600,000	[7]		5,600,000	[7]		3,800,000	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	5,100,000	[7]		5,100,000	[7]		4,200,000	[8]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6]	228,200,000	[7]		228,200,000	[7]		326,500,000	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	243,900,000	[7]		243,900,000	[7]		327,000,000	[8]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6]	407,700,000	[7]		407,700,000	[7]		340,900,000	[8]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	231,600,000	[7]		231,600,000	[7]		185,600,000	[8]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		298,800,000			298,800,000			257,100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		286,800,000			286,800,000			212,500,000
Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	(0.05)			(0.05)			(0.05)
Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	180.10			180.10			176.57
Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	31.34			31.34			33.07
Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		4,500,000			4,500,000			2,500,000
Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	1.96			1.96			2.18
Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	2.62			2.62			3.54
Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	2.25			2.25			2.47
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		111,800,000			111,800,000			96,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		9,000,000			9,000,000			7,400,000
FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	(10.40)			(10.40)			(11.68)
FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	11.65			11.65			17.79
FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	0.54			0.54			1.09
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[6]	12,300,000			12,300,000			34,100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	109,600,000			109,600,000			58,900,000
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6]	(8,200,000)			(8,200,000)			(2,700,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	(8,200,000)			(8,200,000)			(2,700,000)
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0			0			0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6]	17,600,000			17,600,000			24,100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	49,100,000			49,100,000			24,800,000
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6]	2,900,000			2,900,000			12,700,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	68,700,000			68,700,000			36,800,000
Interest Rate [Member]
Risk Management Assets
Risk Management Assets		1,900,000			1,900,000
Interest Rate [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0			0
Interest Rate [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0			0
Interest Rate [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		1,900,000			1,900,000
Interest Rate [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets		25,300,000			25,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		200,000			200,000			17,400,000
Fair Value Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0			0			0
Fair Value Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0			0			0
Fair Value Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		25,300,000			25,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		200,000			200,000			17,400,000
Fair Value Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0			0			0
AEP Texas Inc. [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		114,300,000			114,300,000			156,700,000
AEP Texas Inc. [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
AEP Texas Inc. [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		114,300,000			114,300,000			156,700,000
AEP Texas Inc. [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
AEP Texas Inc. [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	400,000			400,000			200,000
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0			0			(500,000)
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0			0			0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	400,000			400,000			700,000
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6]	0			0			0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		17,100,000			17,100,000			25,600,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		73,800,000			73,800,000			83,700,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		68,500,000		60,000,000	57,800,000		24,700,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	13,800,000		9,000,000	(14,100,000)		104,400,000
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		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)		0		0	0		0
Settlements		(28,100,000)		(19,800,000)	(41,900,000)		(128,300,000)
Transfers into Level 3	[3],[4]	0		0	0		0
Transfers out of Level 3	[4]	0		0	(700,000)		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	1,300,000		17,300,000	54,400,000		65,700,000
Ending Balance		55,500,000		66,500,000	55,500,000		66,500,000
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(32,000,000)			(32,000,000)			(59,400,000)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		17,100,000			17,100,000			25,600,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		17,100,000			17,100,000			25,700,000
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		31,400,000			31,400,000			59,100,000
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		57,300,000			57,300,000			58,300,000
Risk Management Assets
Risk Management Assets		57,300,000			57,300,000			58,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1,800,000			1,800,000			500,000
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	56,700,000			56,700,000			58,100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	1,400,000			1,400,000			600,000
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	(32,000,000)			(32,000,000)			(59,400,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	(33,600,000)			(33,600,000)			(58,500,000)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	0			0			100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	0			0			200,000
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	31,400,000			31,400,000			59,100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	33,200,000			33,200,000			58,400,000
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	57,300,000			57,300,000			58,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	1,800,000			1,800,000			500,000
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		3,600,000			3,600,000			2,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1,100,000			1,100,000			500,000
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	12.93			12.93			16.82
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	59.25			59.25			62.65
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	[9]	31.28			31.28			37
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		53,700,000			53,700,000			55,900,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		700,000			700,000			0
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	(0.91)			(0.91)			0.10
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	10.14			10.14			15.16
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	1.63			1.63			3.27
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,835,200,000			2,835,200,000			2,474,900,000
Total Assets		2,845,800,000			2,845,800,000			2,484,100,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		12,300,000		13,200,000	8,900,000		7,600,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	3,100,000		1,900,000	4,600,000		14,700,000
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		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)		0		0	0		0
Settlements		(7,200,000)		(5,500,000)	(12,600,000)		(21,900,000)
Transfers into Level 3	[3],[4]	0		0	0		0
Transfers out of Level 3	[4]	0		0	(400,000)		(300,000)
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	700,000		(200,000)	8,400,000		9,300,000
Ending Balance		8,900,000		9,400,000	8,900,000		9,400,000
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8,000,000			8,000,000			10,200,000
Total Assets		(13,500,000)			(13,500,000)			(33,000,000)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,703,700,000			1,703,700,000			1,407,600,000
Total Assets		1,703,700,000			1,703,700,000			1,407,600,000
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,500,000			1,123,500,000			1,057,100,000
Total Assets		1,145,400,000			1,145,400,000			1,099,200,000
Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Total Assets		10,200,000			10,200,000			10,300,000
Risk Management Assets
Risk Management Assets		10,200,000			10,200,000			10,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1,300,000			1,300,000			1,400,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	10,600,000			10,600,000			9,200,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	200,000			200,000			400,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	(21,500,000)			(21,500,000)			(43,200,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	(22,400,000)			(22,400,000)			(42,300,000)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	0			0			100,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	21,900,000			21,900,000			42,100,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	21,300,000			21,300,000			41,200,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	10,200,000			10,200,000			10,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	1,300,000			1,300,000			1,400,000
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2,200,000			2,200,000			1,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		700,000			700,000			900,000
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	[9]	12.93			12.93			16.82
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	[9]	59.25			59.25			62.65
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	[9]	31.28			31.28			37
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		8,000,000			8,000,000			8,900,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		600,000			600,000			500,000
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	(1.76)			(1.76)			(2.11)
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	7.26			7.26			6.21
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	[9]	0.87			0.87			1.06
Ohio Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents								27,600,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(111,500,000)		(86,900,000)	(99,400,000)		(132,400,000)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	0		0	(900,000)		1,300,000
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		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)		0		0	0		0
Settlements		1,100,000		600,000	4,600,000		3,000,000
Transfers into Level 3	[3],[4]	0		0	0		0
Transfers out of Level 3	[4]	0		0	0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	(2,100,000)		(8,900,000)	(16,800,000)		32,900,000
Ending Balance		(112,500,000)		(95,200,000)	(112,500,000)		(95,200,000)
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								27,600,000
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]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	112,900,000			112,900,000			99,600,000
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	0			0			(600,000)
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	0			0			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	400,000			400,000			800,000
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	112,500,000			112,500,000			99,400,000
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		112,500,000			112,500,000			99,400,000
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	27.47			27.47			26.29
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	65.81			65.81			62.74
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	[9]	40.30			40.30			42.50
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		27,800,000		24,300,000	9,500,000		6,200,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	4,100,000		3,700,000	13,500,000		18,100,000
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		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)		0		0	0		0
Settlements		(11,200,000)		(10,800,000)	(23,000,000)		(24,300,000)
Transfers into Level 3	[3],[4]	0		0	0		0
Transfers out of Level 3	[4]	0		0	0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	900,000		400,000	21,600,000		17,600,000
Ending Balance		21,600,000		17,600,000	21,600,000		17,600,000
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	21,700,000			21,700,000			10,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	300,000			300,000			1,000,000
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	(300,000)			(300,000)			(400,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	(300,000)			(300,000)			(600,000)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	0			0			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	200,000			200,000			300,000
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	22,000,000			22,000,000			10,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	400,000			400,000			1,300,000
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		22,000,000			22,000,000			10,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		400,000			400,000			1,300,000
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	[9]	(6.87)			(6.87)			(11.68)
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	[9]	0.93			0.93			10.30
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	[9]	(2.19)			(2.19)			(1.40)
Southwestern Electric Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		8,500,000		4,900,000	2,300,000		5,900,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	3,600,000		1,700,000	6,000,000		(4,800,000)
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		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)		0		0	0		0
Settlements		(6,700,000)		(2,700,000)	(10,100,000)		(1,300,000)
Transfers into Level 3	[3],[4]	0		0	0		0
Transfers out of Level 3	[4]	0		0	0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	(500,000)		(400,000)	6,700,000		3,700,000
Ending Balance		4,900,000		$ 3,500,000	4,900,000		$ 3,500,000
Southwestern Electric Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		9,800,000			9,800,000			5,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		4,900,000			4,900,000			3,300,000
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	9,400,000			9,400,000			4,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	4,700,000			4,700,000			2,600,000
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	(400,000)			(400,000)			(800,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	(400,000)			(400,000)			(1,100,000)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	0			0			0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	200,000			200,000			400,000
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[6],[11]	9,800,000			9,800,000			5,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[6],[11]	4,900,000			4,900,000			3,300,000
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		4,500,000			4,500,000			2,500,000
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	[10]	1.96			1.96			2.18
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	[10]	2.62			2.62			3.54
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	[10]	2.25			2.25			2.47
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		9,800,000			9,800,000			5,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		400,000			400,000			800,000
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	(6.87)			(6.87)			(11.68)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[9]	0.93			0.93			10.30
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	[9]	(2.19)			(2.19)			(1.40)
Cash [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[12],[13]	160,100,000			160,100,000			230,600,000
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13]	7,200,000			7,200,000			9,100,000
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13]	152,900,000			152,900,000			221,500,000
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13]	0			0			0
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13]	0			0			0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,500,000			1,123,500,000			1,057,100,000
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,500,000			1,123,500,000			1,057,100,000
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,500,000			1,123,500,000			1,057,100,000
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,500,000			1,123,500,000			1,057,100,000
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[14]	133,200,000			133,200,000			104,300,000
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		133,200,000			133,200,000			104,300,000
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	46,100,000			46,100,000			34,200,000
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	0			0			0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	46,100,000			46,100,000			34,200,000
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	0			0			0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	0			0			0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	17,400,000			17,400,000			22,500,000
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	8,000,000			8,000,000			10,200,000
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	9,400,000			9,400,000			12,300,000
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	17,400,000			17,400,000			22,500,000
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	8,000,000			8,000,000			10,200,000
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	[16]	9,400,000			9,400,000			12,300,000
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	[16]	0			0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,047,400,000			1,047,400,000			996,100,000
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,047,400,000			1,047,400,000			996,100,000
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,047,400,000			1,047,400,000			996,100,000
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,047,400,000			1,047,400,000			996,100,000
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		68,600,000			68,600,000			52,400,000
Corporate Debt [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		68,600,000			68,600,000			52,400,000
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		68,600,000			68,600,000			52,400,000
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		68,600,000			68,600,000			52,400,000
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7,500,000			7,500,000			8,600,000
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7,500,000			7,500,000			8,600,000
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7,500,000			7,500,000			8,600,000
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7,500,000			7,500,000			8,600,000
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,694,300,000			1,694,300,000			1,395,300,000
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0			0			0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,694,300,000			1,694,300,000			1,395,300,000
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0			0			0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,694,300,000			1,694,300,000			1,395,300,000
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,694,300,000			1,694,300,000			1,395,300,000
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	$ 0			$ 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 September 30, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2019, $(8) million in periods 2020-2022 and $(1) million in periods 2025-2032; Level 3 matures $40 million in 2019, $114 million in periods 2020-2022, $26 million in periods 2023-2024 and $(4) million in periods 2025-2032. Risk management commodity contracts are substantially comprised of power contracts.
[8]	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.
[9]	Represents market prices in dollars per MWh.
[10]	Represents market prices in dollars per MMBtu.
[11]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[12]	Primarily represents amounts held for the repayment of debt.
[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 short and intermediate maturities which may be sold and do not contain maturity dates.
[15]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[16]	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		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	5.20%	(16.20%)	1.70%	5.60%
Income Tax Expense (Benefit)	$ (40.6)	$ 80.7	$ (30.7)	$ (93.5)
Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 71		$ (93)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	19.10%		(4.50%)
State Income Tax Expenses [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 14
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	1.30%
Kentucky Legislation - House Bill 487 [Member]
Kentucky Single Corporate Tax Rate				5.00%
Kentucky Legislation - House Bill 366 [Member]
Kentucky Net Operating Loss Limitation Percent				80.00%
Remeasurement of Kentucky Deferred Taxes [Member]
Income Tax Expense (Benefit)		$ 18
AEP Texas Inc. [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	15.10%	12.60%	(25.30%)	14.90%
Income Tax Expense (Benefit)	$ (13.7)	$ (8.3)	$ 38.8	$ (26.4)
AEP Texas Inc. [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount			$ (59)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent			(38.90%)
AEP Transmission Co [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	21.90%	18.40%	20.70%	20.70%
Income Tax Expense (Benefit)	$ (30.1)	$ (17.6)	$ (90.7)	$ (63.7)
AEP Transmission Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 2
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	1.00%
AEP Transmission Co [Member] | State Income Tax Expenses [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 3
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	1.30%
AEP Transmission Co [Member] | Kentucky Legislation - House Bill 487 [Member]
Kentucky Single Corporate Tax Rate				5.00%
AEP Transmission Co [Member] | Kentucky Legislation - House Bill 366 [Member]
Kentucky Net Operating Loss Limitation Percent				80.00%
Appalachian Power Co [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	(3.90%)	(962.20%)	(19.10%)	(13.80%)
Income Tax Expense (Benefit)	$ 3.9	$ 78.9	$ 47	$ 35.1
Appalachian Power Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 56		$ (9)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	947.30%		(4.60%)
Appalachian Power Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member] | West Virginia Tax Reform [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount		$ (73)
Appalachian Power Co [Member] | State Income Tax Expenses [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 6
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	34.80%
Indiana Michigan Power Co [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	(2.70%)	15.90%	(2.10%)	10.40%
Income Tax Expense (Benefit)	$ 2.3	$ (13.7)	$ 5.1	$ (26.8)
Indiana Michigan Power Co [Member] | Amortization of Excess ADIT [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ (10)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	(11.30%)		(6.90%)
Indiana Michigan Power Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount			$ (16)
Indiana Michigan Power Co [Member] | Flow-Through Items [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ (3)		$ (12)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	(3.20%)		(4.80%)
Indiana Michigan Power Co [Member] | State Income Tax Expenses [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 2
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	(1.80%)
Indiana Michigan Power Co [Member] | Parent Company Loss Benefit [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ (1)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	(1.60%)
Indiana Michigan Power Co [Member] | Kentucky Legislation - House Bill 487 [Member]
Kentucky Single Corporate Tax Rate				5.00%
Indiana Michigan Power Co [Member] | Kentucky Legislation - House Bill 366 [Member]
Kentucky Net Operating Loss Limitation Percent				80.00%
Ohio Power Co [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	13.90%	(46.40%)	14.20%	4.60%
Income Tax Expense (Benefit)	$ (11.2)	$ 28.1	$ (40.9)	$ (11.4)
Ohio Power Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 35		$ 24
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	60.00%		10.80%
Ohio Power Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member] | Ohio Tax Reform [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount		$ (38)		$ (38)
Ohio Power Co [Member] | Parent Company Loss Benefit [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ 1
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	2.00%
Ohio Power Co [Member] | Kentucky Legislation - House Bill 487 [Member]
Kentucky Single Corporate Tax Rate				5.00%
Ohio Power Co [Member] | Kentucky Legislation - House Bill 366 [Member]
Kentucky Net Operating Loss Limitation Percent				80.00%
Public Service Co Of Oklahoma [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	6.40%	5.60%	4.60%	8.70%
Income Tax Expense (Benefit)	$ (6.9)	$ (3.6)	$ (7.2)	$ (8.6)
Public Service Co Of Oklahoma [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount			$ (15)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent			(6.80%)
Southwestern Electric Power Co [Member]
Federal Statutory Income Tax Rate	21.00%	21.00%	21.00%	21.00%
Effective Income Tax Rate	(0.60%)	9.80%	0.00%	11.40%
Income Tax Expense (Benefit)	$ 0.7	$ (9.6)	$ 0	$ (17.9)
Southwestern Electric Power Co [Member] | Amortization of Excess ADIT Not Subject to Normalization Requirements [Member]
Effective Income Tax Rate Reconciliation, Variance Explanation, Amount	$ (11)		$ (15)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent	(9.70%)		10.40%

Leases (Details)

Leases (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Lease Rental Costs
Operating Lease, Cost	$ 64.4	$ 200.3
Finance Lease Right-of-Use Asset Amortization	16.5	45
Interest Expense on Finance Leases	4.1	12.2
Total Lease Rental Costs	$ 85	$ 257.5
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	5 years 3 months 21 days	5 years 3 months 21 days
Weighted Average Remaining Lease Term, Finance Leases	5 years 10 months 13 days	5 years 10 months 13 days
Weighted Average Discount Rate, Operating Leases	3.61%	3.61%
Weighted Average Discount Rate, Finance Leases	6.02%	6.02%
Operating Cash Flows Used for Operating Leases		$ 163.6
Operating Cash Flows Used for Finance Leases		11
Financing Cash Flows Used for Finance Leases		44.5	$ 49.4
Non-cash Acquisitions Under Operating Leases		108.9
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	$ 22,624.4	22,624.4		$ 21,699.9
Other Property, Plant and Equipment	4,510.2	4,510.2		4,265
Total Property, Plant and Equipment	77,452.9	77,452.9		73,085.2
Accumulated Amortization	18,760.2	18,760.2		17,986.1
Net Property, Plant and Equipment Under Finance Leases	308.1	308.1
Obligations Under Finance Leases Noncurrent	790	790		782.6
Finance Lease Liability Due Within One Year	1,032.4	1,032.4		1,190.5
Total Obligations Under Finance Leases	315.4	315.4
Operating Lease Asset and Related Obligations
Operating Lease Assets	990	990		0
Operating Lease Assets, Noncurrent	11,041.6	11,041.6		9,589.8
Operating Lease Noncurrent Liability	801.1	801.1		0
Operating Lease Liability Due Within One Year	228.8	228.8		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	1,029.9	1,029.9
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	76.8	76.8
Finance Leases, Year 2	67	67
Finance Leases, Year 3	58	58
Finance Leases, Year 4	49	49
Finance Leases, Year 5	50	50
Finance Leases, Later Years	76.1	76.1
Finance Leases, Total Future Minimum Lease Payments	376.9	376.9
Imputed Interest on Finance Leases	61.5	61.5
Total Obligations Under Finance Leases	315.4	315.4
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	267.5	267.5
Operating Leases, Year 2	252.4	252.4
Operating Leases, Year 3	239.9	239.9
Operating Leases, Year 4	154.2	154.2
Operating Leases, Year 5	63.6	63.6
Operating Leases, Later Years	184.1	184.1
Operating Leases, Total Future Minimum Lease Payments	1,161.7	1,161.7
Imputed Interest on Operating Leases	131.8	131.8
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	1,029.9	1,029.9
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				70.8
Finance Leases, 2020				60.2
Finance Leases, 2021				51.7
Finance Leases, 2022				43.8
Finance Leases, 2023				35.5
Finance Leases, Later Years				90.2
Finance Leases, Total Future Minimum Payments Due				352.2
Estimated Interest Element on Finance Leases				63.2
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				289
Operating Lease Future Minimum Lease Payments
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	46.6	46.6
Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2019	74.2	74.2
2020	147.8	147.8
2021	147.8	147.8
2022	147.2	147.2
Total Future Minimum Lease Payments	517	517
Leases (Textuals)
Sale and Leaseback Transaction, Gain (Loss), Net		$ 37
Lease Term		33 years
Boat and Barge Leases [Member]
Leases (Textuals)
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases	56	$ 56
Guarantor Obligations, Current Carrying Value	4	4
Guarantee Obligations Current Carrying Value Other Liabilities Current	1	1
Guarantee Obligations Current Carrying Value Other Liabilities Noncurrent	3	3
Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	134.9	134.9
Other Property, Plant and Equipment	335.9	335.9
Total Property, Plant and Equipment	470.8	470.8
Accumulated Amortization	162.7	162.7
Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	254	254
Finance Lease Liability Due Within One Year	61.4	61.4
AEP Texas Inc. [Member]
Lease Rental Costs
Operating Lease, Cost	4	12.2
Finance Lease Right-of-Use Asset Amortization	1.5	3.8
Interest Expense on Finance Leases	0.3	1
Total Lease Rental Costs	$ 5.8	$ 17
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	7 years 18 days	7 years 18 days
Weighted Average Remaining Lease Term, Finance Leases	6 years 10 months 9 days	6 years 10 months 9 days
Weighted Average Discount Rate, Operating Leases	3.79%	3.79%
Weighted Average Discount Rate, Finance Leases	4.71%	4.71%
Operating Cash Flows Used for Operating Leases		$ 11.4
Operating Cash Flows Used for Finance Leases		1
Financing Cash Flows Used for Finance Leases		3.8	3.6
Non-cash Acquisitions Under Operating Leases		12.7
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	$ 351.8	351.8		352.1
Other Property, Plant and Equipment	775.3	775.3		727.9
Total Property, Plant and Equipment	10,330.5	10,330.5		9,643
Accumulated Amortization	1,742.7	1,742.7		1,651.2
Net Property, Plant and Equipment Under Finance Leases	31	31
Obligations Under Finance Leases Noncurrent	137.1	137.1		104
Finance Lease Liability Due Within One Year	85.1	85.1		98.3
Total Obligations Under Finance Leases	31	31
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	1,119.6	1,119.6		1,135.4
Operating Lease Noncurrent Liability	71.1	71.1		0
Operating Lease Liability Due Within One Year	11.7	11.7		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	82.8	82.8
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	6.6	6.6
Finance Leases, Year 2	6.1	6.1
Finance Leases, Year 3	5.3	5.3
Finance Leases, Year 4	4.9	4.9
Finance Leases, Year 5	4.1	4.1
Finance Leases, Later Years	9.8	9.8
Finance Leases, Total Future Minimum Lease Payments	36.8	36.8
Imputed Interest on Finance Leases	5.8	5.8
Total Obligations Under Finance Leases	31	31
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	15.7	15.7
Operating Leases, Year 2	15.2	15.2
Operating Leases, Year 3	14.1	14.1
Operating Leases, Year 4	13	13
Operating Leases, Year 5	11.4	11.4
Operating Leases, Later Years	27.8	27.8
Operating Leases, Total Future Minimum Lease Payments	97.2	97.2
Imputed Interest on Operating Leases	14.4	14.4
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	82.8	82.8
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				5.8
Finance Leases, 2020				5.3
Finance Leases, 2021				4.7
Finance Leases, 2022				4.2
Finance Leases, 2023				3.7
Finance Leases, Later Years				10.1
Finance Leases, Total Future Minimum Payments Due				33.8
Estimated Interest Element on Finance Leases				5.3
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				28.5
Operating Lease Future Minimum Lease Payments
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	11.2	11.2
AEP Texas Inc. [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	0	0
Other Property, Plant and Equipment	41.9	41.9
Total Property, Plant and Equipment	41.9	41.9
Accumulated Amortization	10.9	10.9
AEP Texas Inc. [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	25.8	25.8
Finance Lease Liability Due Within One Year	5.2	5.2
AEP Texas Inc. [Member] | Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	82	82
AEP Transmission Co [Member]
Lease Rental Costs
Operating Lease, Cost	0.6	1.7
Finance Lease Right-of-Use Asset Amortization	0.1	0.1
Interest Expense on Finance Leases	0	0
Total Lease Rental Costs	$ 0.7	$ 1.8
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	2 years 5 months 4 days	2 years 5 months 4 days
Weighted Average Remaining Lease Term, Finance Leases	17 days	17 days
Weighted Average Discount Rate, Operating Leases	3.13%	3.13%
Weighted Average Discount Rate, Finance Leases	9.33%	9.33%
Operating Cash Flows Used for Operating Leases		$ 1.7
Operating Cash Flows Used for Finance Leases		0
Financing Cash Flows Used for Finance Leases		0
Non-cash Acquisitions Under Operating Leases		0
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Property, Plant and Equipment	$ 227.2	227.2		174
Total Property, Plant and Equipment	9,267.4	9,267.4		8,268.1
Accumulated Amortization	368.8	368.8		271.9
Net Property, Plant and Equipment Under Finance Leases	0	0
Obligations Under Finance Leases Noncurrent	3.1	3.1		18.4
Finance Lease Liability Due Within One Year	25.5	25.5		3.8
Total Obligations Under Finance Leases	0	0
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	64.9	64.9		172.4
Operating Lease Noncurrent Liability	2.2	2.2		0
Operating Lease Liability Due Within One Year	2.3	2.3		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	4.5	4.5
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	0	0
Finance Leases, Year 2	0	0
Finance Leases, Year 3	0	0
Finance Leases, Year 4	0	0
Finance Leases, Year 5	0	0
Finance Leases, Later Years	0	0
Finance Leases, Total Future Minimum Lease Payments	0	0
Imputed Interest on Finance Leases	0	0
Total Obligations Under Finance Leases	0	0
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	2.4	2.4
Operating Leases, Year 2	1.5	1.5
Operating Leases, Year 3	0.7	0.7
Operating Leases, Year 4	0.3	0.3
Operating Leases, Year 5	0	0
Operating Leases, Later Years	0	0
Operating Leases, Total Future Minimum Lease Payments	4.9	4.9
Imputed Interest on Operating Leases	0.4	0.4
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	4.5	4.5
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				0.1
Finance Leases, 2020				0
Finance Leases, 2021				0
Finance Leases, 2022				0
Finance Leases, 2023				0
Finance Leases, Later Years				0
Finance Leases, Total Future Minimum Payments Due				0.1
Estimated Interest Element on Finance Leases				0
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				0.1
Operating Lease Future Minimum Lease Payments
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
AEP Transmission Co [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	0	0
Other Property, Plant and Equipment	0.2	0.2
Total Property, Plant and Equipment	0.2	0.2
Accumulated Amortization	0.2	0.2
AEP Transmission Co [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	0	0
Finance Lease Liability Due Within One Year	0	0
AEP Transmission Co [Member] | Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	4.6	4.6
Appalachian Power Co [Member]
Lease Rental Costs
Operating Lease, Cost	4.9	14.5
Finance Lease Right-of-Use Asset Amortization	2	5
Interest Expense on Finance Leases	0.8	2.2
Total Lease Rental Costs	$ 7.7	$ 21.7
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	6 years 3 months	6 years 3 months
Weighted Average Remaining Lease Term, Finance Leases	6 years 3 months 29 days	6 years 3 months 29 days
Weighted Average Discount Rate, Operating Leases	3.67%	3.67%
Weighted Average Discount Rate, Finance Leases	8.19%	8.19%
Operating Cash Flows Used for Operating Leases		$ 14.1
Operating Cash Flows Used for Finance Leases		2.2
Financing Cash Flows Used for Finance Leases		5	5.2
Non-cash Acquisitions Under Operating Leases		8.6
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	$ 6,560.5	6,560.5		6,509.6
Other Property, Plant and Equipment	525.3	525.3		485.8
Total Property, Plant and Equipment	15,292.3	15,292.3		14,792.7
Accumulated Amortization	4,300.2	4,300.2		4,124.4
Net Property, Plant and Equipment Under Finance Leases	41.9	41.9
Obligations Under Finance Leases Noncurrent	57.5	57.5		58.6
Finance Lease Liability Due Within One Year	107.6	107.6		150.3
Total Obligations Under Finance Leases	41.9	41.9
Operating Lease Asset and Related Obligations
Operating Lease Assets	79.4	79.4		0
Operating Lease Assets, Noncurrent	953.7	953.7		923.5
Operating Lease Noncurrent Liability	64.8	64.8		0
Operating Lease Liability Due Within One Year	15.3	15.3		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	80.1	80.1
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	9.6	9.6
Finance Leases, Year 2	8.8	8.8
Finance Leases, Year 3	8.1	8.1
Finance Leases, Year 4	7.5	7.5
Finance Leases, Year 5	7	7
Finance Leases, Later Years	11.3	11.3
Finance Leases, Total Future Minimum Lease Payments	52.3	52.3
Imputed Interest on Finance Leases	10.4	10.4
Total Obligations Under Finance Leases	41.9	41.9
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	18.4	18.4
Operating Leases, Year 2	16.4	16.4
Operating Leases, Year 3	14.7	14.7
Operating Leases, Year 4	12.5	12.5
Operating Leases, Year 5	9.8	9.8
Operating Leases, Later Years	20.1	20.1
Operating Leases, Total Future Minimum Lease Payments	91.9	91.9
Imputed Interest on Operating Leases	11.8	11.8
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	80.1	80.1
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				9
Finance Leases, 2020				8
Finance Leases, 2021				7.3
Finance Leases, 2022				6.8
Finance Leases, 2023				6.3
Finance Leases, Later Years				13.3
Finance Leases, Total Future Minimum Payments Due				50.7
Estimated Interest Element on Finance Leases				10.9
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				39.8
Operating Lease Future Minimum Lease Payments
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	6.3	6.3
Appalachian Power Co [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	41.3	41.3
Other Property, Plant and Equipment	18.4	18.4
Total Property, Plant and Equipment	59.7	59.7
Accumulated Amortization	17.8	17.8
Appalachian Power Co [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	35.2	35.2
Finance Lease Liability Due Within One Year	6.7	6.7
Indiana Michigan Power Co [Member]
Lease Rental Costs
Operating Lease, Cost	23.7	70
Finance Lease Right-of-Use Asset Amortization	1.6	4.2
Interest Expense on Finance Leases	0.8	2.3
Total Lease Rental Costs	$ 26.1	$ 76.5
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	4 years 18 days	4 years 18 days
Weighted Average Remaining Lease Term, Finance Leases	6 years 8 months 19 days	6 years 8 months 19 days
Weighted Average Discount Rate, Operating Leases	3.45%	3.45%
Weighted Average Discount Rate, Finance Leases	8.61%	8.61%
Operating Cash Flows Used for Operating Leases		$ 52.5
Operating Cash Flows Used for Finance Leases		2.2
Financing Cash Flows Used for Finance Leases		4	7.3
Non-cash Acquisitions Under Operating Leases		16.6
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	$ 5,002	5,002		4,887.2
Other Property, Plant and Equipment	607.2	607.2		583.8
Total Property, Plant and Equipment	10,113.2	10,113.2		9,762.8
Accumulated Amortization	3,280.5	3,280.5		3,151.6
Net Property, Plant and Equipment Under Finance Leases	42.8	42.8
Obligations Under Finance Leases Noncurrent	65.6	65.6		87.8
Finance Lease Liability Due Within One Year	85.5	85.5		103
Total Obligations Under Finance Leases	43.1	43.1
Operating Lease Asset and Related Obligations
Operating Lease Assets	295.3	295.3		0
Operating Lease Assets, Noncurrent	3,750.4	3,750.4		3,181
Operating Lease Noncurrent Liability	234	234		0
Operating Lease Liability Due Within One Year	82	82		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	316	316
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	9	9
Finance Leases, Year 2	8.2	8.2
Finance Leases, Year 3	7.6	7.6
Finance Leases, Year 4	7.1	7.1
Finance Leases, Year 5	6.7	6.7
Finance Leases, Later Years	20.9	20.9
Finance Leases, Total Future Minimum Lease Payments	59.5	59.5
Imputed Interest on Finance Leases	16.4	16.4
Total Obligations Under Finance Leases	43.1	43.1
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	92.2	92.2
Operating Leases, Year 2	88.4	88.4
Operating Leases, Year 3	86.3	86.3
Operating Leases, Year 4	48	48
Operating Leases, Year 5	7.3	7.3
Operating Leases, Later Years	22	22
Operating Leases, Total Future Minimum Lease Payments	344.2	344.2
Imputed Interest on Operating Leases	28.2	28.2
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	316	316
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				8.2
Finance Leases, 2020				7.2
Finance Leases, 2021				6.6
Finance Leases, 2022				6.1
Finance Leases, 2023				5.7
Finance Leases, Later Years				21.7
Finance Leases, Total Future Minimum Payments Due				55.5
Estimated Interest Element on Finance Leases				16.8
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				38.7
Operating Lease Future Minimum Lease Payments
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	4	4
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2019	37.1	37.1
2020	73.9	73.9
2021	73.9	73.9
2022	73.6	73.6
Total Future Minimum Lease Payments	258.5	258.5
Leases (Textuals)
Sale and Leaseback Transaction, Gain (Loss), Net		$ 15
Lease Term		33 years
Indiana Michigan Power Co [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	28.5	$ 28.5
Other Property, Plant and Equipment	37.1	37.1
Total Property, Plant and Equipment	65.6	65.6
Accumulated Amortization	22.8	22.8
Indiana Michigan Power Co [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	37.1	37.1
Finance Lease Liability Due Within One Year	6	6
Ohio Power Co [Member]
Lease Rental Costs
Operating Lease, Cost	4.9	13.8
Finance Lease Right-of-Use Asset Amortization	1.1	2.6
Interest Expense on Finance Leases	0.2	0.5
Total Lease Rental Costs	$ 6.2	$ 16.9
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	8 years 1 month 6 days	8 years 1 month 6 days
Weighted Average Remaining Lease Term, Finance Leases	6 years 6 months 29 days	6 years 6 months 29 days
Weighted Average Discount Rate, Operating Leases	3.79%	3.79%
Weighted Average Discount Rate, Finance Leases	4.66%	4.66%
Operating Cash Flows Used for Operating Leases		$ 13.8
Operating Cash Flows Used for Finance Leases		0.5
Financing Cash Flows Used for Finance Leases		2.6	2.9
Non-cash Acquisitions Under Operating Leases		34.6
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Property, Plant and Equipment	$ 662.3	662.3		574.8
Total Property, Plant and Equipment	8,953.4	8,953.4		8,493.5
Accumulated Amortization	2,256.1	2,256.1		2,218.6
Net Property, Plant and Equipment Under Finance Leases	18.1	18.1
Obligations Under Finance Leases Noncurrent	49.9	49.9		43.8
Finance Lease Liability Due Within One Year	99.4	99.4		182.8
Total Obligations Under Finance Leases	18.1	18.1
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	692.5	692.5		841.4
Operating Lease Noncurrent Liability	75.9	75.9		0
Operating Lease Liability Due Within One Year	12.8	12.8		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	88.7	88.7
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	4.3	4.3
Finance Leases, Year 2	3.9	3.9
Finance Leases, Year 3	3.2	3.2
Finance Leases, Year 4	2.5	2.5
Finance Leases, Year 5	2.1	2.1
Finance Leases, Later Years	5.3	5.3
Finance Leases, Total Future Minimum Lease Payments	21.3	21.3
Imputed Interest on Finance Leases	3.2	3.2
Total Obligations Under Finance Leases	18.1	18.1
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	16.6	16.6
Operating Leases, Year 2	13.9	13.9
Operating Leases, Year 3	13.3	13.3
Operating Leases, Year 4	12.4	12.4
Operating Leases, Year 5	10.8	10.8
Operating Leases, Later Years	38.3	38.3
Operating Leases, Total Future Minimum Lease Payments	105.3	105.3
Imputed Interest on Operating Leases	16.6	16.6
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	88.7	88.7
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				3.3
Finance Leases, 2020				2.7
Finance Leases, 2021				2.3
Finance Leases, 2022				1.7
Finance Leases, 2023				1.2
Finance Leases, Later Years				2.8
Finance Leases, Total Future Minimum Payments Due				14
Estimated Interest Element on Finance Leases				1.9
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				12.1
Operating Lease Future Minimum Lease Payments
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	7.4	7.4
Ohio Power Co [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	0	0
Other Property, Plant and Equipment	24.7	24.7
Total Property, Plant and Equipment	24.7	24.7
Accumulated Amortization	6.6	6.6
Ohio Power Co [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	14.5	14.5
Finance Lease Liability Due Within One Year	3.6	3.6
Ohio Power Co [Member] | Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	88.2	88.2
Public Service Co Of Oklahoma [Member]
Lease Rental Costs
Operating Lease, Cost	1.5	5
Finance Lease Right-of-Use Asset Amortization	0.8	2.2
Interest Expense on Finance Leases	0.1	0.4
Total Lease Rental Costs	$ 2.4	$ 7.6
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	7 years 21 days	7 years 21 days
Weighted Average Remaining Lease Term, Finance Leases	6 years 2 months 26 days	6 years 2 months 26 days
Weighted Average Discount Rate, Operating Leases	3.68%	3.68%
Weighted Average Discount Rate, Finance Leases	4.73%	4.73%
Operating Cash Flows Used for Operating Leases		$ 4.9
Operating Cash Flows Used for Finance Leases		0.4
Financing Cash Flows Used for Finance Leases		2.2	2.5
Non-cash Acquisitions Under Operating Leases		7.3
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	$ 1,569.9	1,569.9		1,577
Other Property, Plant and Equipment	319.6	319.6		303.5
Total Property, Plant and Equipment	5,596.8	5,596.8		5,439.6
Accumulated Amortization	1,558.5	1,558.5		1,472.9
Net Property, Plant and Equipment Under Finance Leases	14.2	14.2
Obligations Under Finance Leases Noncurrent	26.1	26.1		32.5
Finance Lease Liability Due Within One Year	67.7	67.7		64.5
Total Obligations Under Finance Leases	14.2	14.2
Operating Lease Asset and Related Obligations
Operating Lease Assets	37.1	37.1		0
Operating Lease Assets, Noncurrent	467.6	467.6		407.8
Operating Lease Noncurrent Liability	31.2	31.2		0
Operating Lease Liability Due Within One Year	6	6		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	37.2	37.2
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	3.8	3.8
Finance Leases, Year 2	3.1	3.1
Finance Leases, Year 3	2.3	2.3
Finance Leases, Year 4	2.1	2.1
Finance Leases, Year 5	1.7	1.7
Finance Leases, Later Years	3.7	3.7
Finance Leases, Total Future Minimum Lease Payments	16.7	16.7
Imputed Interest on Finance Leases	2.5	2.5
Total Obligations Under Finance Leases	14.2	14.2
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	7.4	7.4
Operating Leases, Year 2	6.6	6.6
Operating Leases, Year 3	6	6
Operating Leases, Year 4	5.5	5.5
Operating Leases, Year 5	5	5
Operating Leases, Later Years	12.7	12.7
Operating Leases, Total Future Minimum Lease Payments	43.2	43.2
Imputed Interest on Operating Leases	6	6
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	37.2	37.2
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				3.4
Finance Leases, 2020				2.6
Finance Leases, 2021				2
Finance Leases, 2022				1.6
Finance Leases, 2023				1.4
Finance Leases, Later Years				3.3
Finance Leases, Total Future Minimum Payments Due				14.3
Estimated Interest Element on Finance Leases				2
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				12.3
Operating Lease Future Minimum Lease Payments
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	4.3	4.3
Public Service Co Of Oklahoma [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	2.6	2.6
Other Property, Plant and Equipment	20.7	20.7
Total Property, Plant and Equipment	23.3	23.3
Accumulated Amortization	9.1	9.1
Public Service Co Of Oklahoma [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	11	11
Finance Lease Liability Due Within One Year	3.2	3.2
Southwestern Electric Power Co [Member]
Lease Rental Costs
Operating Lease, Cost	1.8	5.7
Finance Lease Right-of-Use Asset Amortization	2.8	8.2
Interest Expense on Finance Leases	0.7	2.2
Total Lease Rental Costs	$ 5.3	$ 16.1
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases	6 years 7 months 17 days	6 years 7 months 17 days
Weighted Average Remaining Lease Term, Finance Leases	5 years 4 months 2 days	5 years 4 months 2 days
Weighted Average Discount Rate, Operating Leases	3.80%	3.80%
Weighted Average Discount Rate, Finance Leases	5.03%	5.03%
Operating Cash Flows Used for Operating Leases		$ 5.3
Operating Cash Flows Used for Finance Leases		1.1
Financing Cash Flows Used for Finance Leases		8.1	$ 8.5
Non-cash Acquisitions Under Operating Leases		10.6
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	$ 4,676.1	4,676.1		4,672.6
Other Property, Plant and Equipment	703.2	703.2		762.7
Total Property, Plant and Equipment	9,851.3	9,851.3		9,680.1
Accumulated Amortization	2,848.2	2,848.2		2,808.3
Net Property, Plant and Equipment Under Finance Leases	58	58
Obligations Under Finance Leases Noncurrent	108.3	108.3		126.8
Finance Lease Liability Due Within One Year	108	108		106.4
Total Obligations Under Finance Leases	61.7	61.7
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	390.8	390.8		342
Operating Lease Noncurrent Liability	32.5	32.5		0
Operating Lease Liability Due Within One Year	5.9	5.9		0
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	38.4	38.4
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Finance Leases, Year 1	13	13
Finance Leases, Year 2	11.6	11.6
Finance Leases, Year 3	10.6	10.6
Finance Leases, Year 4	9.5	9.5
Finance Leases, Year 5	14.8	14.8
Finance Leases, Later Years	7.5	7.5
Finance Leases, Total Future Minimum Lease Payments	67	67
Imputed Interest on Finance Leases	5.3	5.3
Total Obligations Under Finance Leases	61.7	61.7
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Operating Leases, Year 1	8.4	8.4
Operating Leases, Year 2	8.2	8.2
Operating Leases, Year 3	7.5	7.5
Operating Leases, Year 4	7.2	7.2
Operating Leases, Year 5	5	5
Operating Leases, Later Years	12.4	12.4
Operating Leases, Total Future Minimum Lease Payments	48.7	48.7
Imputed Interest on Operating Leases	10.3	10.3
Estimated Present Value of Future Minimum Lease Payments on Operating Leases	38.4	38.4
Finance Lease Future Minimum Lease Payments
Finance Leases, 2019				13.1
Finance Leases, 2020				11.5
Finance Leases, 2021				10.5
Finance Leases, 2022				9.4
Finance Leases, 2023				8.6
Finance Leases, Later Years				18.7
Finance Leases, Total Future Minimum Payments Due				71.8
Estimated Interest Element on Finance Leases				11
Estimated Present Value of Future Minimum Lease Payments on Finance Leases				60.8
Operating Lease Future Minimum Lease Payments
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	4.7	4.7
Southwestern Electric Power Co [Member] | Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation	34.2	34.2
Other Property, Plant and Equipment	50	50
Total Property, Plant and Equipment	84.2	84.2
Accumulated Amortization	26.2	26.2
Southwestern Electric Power Co [Member] | Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Obligations Under Finance Leases Noncurrent	50.5	50.5
Finance Lease Liability Due Within One Year	11.2	11.2
Southwestern Electric Power Co [Member] | Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets, Noncurrent	$ 40.8	$ 40.8

Financing Activities (Details)

Financing Activities (Details) - USD ($)		1 Months Ended	3 Months Ended						9 Months Ended
		Oct. 24, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Long-term Debt
Senior Unsecured Notes			$ 20,829,200,000						$ 20,829,200,000		$ 18,903,300,000
Pollution Control Bonds			1,516,500,000						1,516,500,000		1,643,800,000
Notes Payable			189,100,000						189,100,000		204,700,000
Securitization Bonds			1,059,400,000						1,059,400,000		1,111,400,000
Spent Nuclear Fuel Obligation	[1]		278,500,000						278,500,000		273,600,000
Junior Subordinated Notes	[2]		786,800,000						786,800,000		0
Other Long-term Debt			1,221,700,000						1,221,700,000		1,209,900,000
Total Long-term Debt Outstanding			25,881,200,000						25,881,200,000		23,346,700,000
Long-term Debt Due Within One Year			1,327,700,000						1,327,700,000		1,698,500,000
Long-term Debt			24,553,500,000						24,553,500,000		21,648,200,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								3,549,000,000
Repayments of Long-term Debt									1,023,500,000	$ 1,959,500,000
Short-term Debt:
Securitized Debt for Receivables	[4]		750,000,000						750,000,000		750,000,000
Commercial Paper			1,760,000,000						1,760,000,000		1,160,000,000
Total Short-term Debt			$ 2,510,000,000						$ 2,510,000,000		$ 1,910,000,000
Securitized Debt for Receivables	[4],[5]		2.56%						2.56%		2.16%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable			2.37%			2.27%			2.56%	2.06%
Net Uncollectible Accounts Receivable Written Off			$ 8,800,000			$ 9,600,000			$ 19,800,000	$ 19,000,000
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts			923,300,000						923,300,000		$ 972,500,000
Total Principal Outstanding			750,000,000						750,000,000		750,000,000
Delinquent Securitized Accounts Receivable			43,900,000						43,900,000		50,300,000
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable			32,300,000						32,300,000		27,500,000
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable			216,200,000						216,200,000		281,400,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			4,315,000,000			4,333,100,000			11,945,400,000	12,394,600,000
Financing Activities (Textuals)
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			322,000,000						322,000,000		$ 317,000,000
Reacquired Pollution Controls Bonds Held by Trustees			574,000,000						$ 574,000,000
Maximum Percentage Debt to Capitalization									67.50%
Total Commitment from Bank Conduits to Finance Receivables			750,000,000						$ 750,000,000
Equity Units Issued									16,100,000
Per Unit Conversion for Equity Units			50						$ 50
Net Equity Units Issuance Proceeds									785,000,000
Principal Amounts of Junior Subordinated Debt			$ 1,000						$ 1,000
Forward Equity Purchase Contract Date									2022
Equity Units Annual Distribution Rate			6.125%						6.125%
Forward Equity Contract Payment Rate			2.725%						2.725%
Stockholders' Equity, Other			$ (500,000)	$ (2,500,000)	$ 55,600,000	(3,600,000)	$ 1,500,000	$ (16,900,000)
Maximum Shares Issued Under Equity Units Conversion									9,701,860
Junior Subordinated Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3],[6]								$ 805,000,000
Due Date	[6]								2024
Interest Rate (Percentage)	[6]		3.40%						3.40%
Pollution Control Bonds [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt		$ 240,000,000
Commercial Paper [Member]
Short-term Debt:
Weighted Average Interest Rate	[5]		2.36%						2.36%		2.96%
AEP Texas Inc. [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 4,146,500,000						$ 4,146,500,000		$ 3,881,300,000
Long-term Debt Due Within One Year			391,400,000						391,400,000		501,100,000
Long-term Debt			3,755,100,000						3,755,100,000		3,380,200,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 366,800,000	$ 231,700,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization									67.50%
AEP Texas Inc. [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 390,700,000
Maximum Loans to Money Pool									0
Average Borrowings from Money Pool									261,800,000
Average Loans to Money Pool									0
Net Loans (Borrowings) to/from Money Pool			(74,800,000)						(74,800,000)
Authorized Short Term Borrowing Limit									$ 500,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.71%	2.25%
Average Interest Rate For Funds Loaned									0.00%	2.29%
AEP Texas Inc. [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Loans to Money Pool									$ 8,000,000
Average Loans to Money Pool									7,700,000
Net Loans (Borrowings) to/from Money Pool			$ 7,700,000						$ 7,700,000
Maximum and Minimum Interest Rates
Maximum Interest Rate For Funds Loaned									3.02%	2.52%
Minimum Interest Rate for Funds Loaned									2.36%	1.83%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Loaned									2.70%	2.26%
AEP Texas Inc. [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 100,600,000
Due Date									2029
Interest Rate (Percentage)			2.60%						2.60%
AEP Texas Inc. [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 100,600,000
Due Date									2029
Interest Rate (Percentage)			6.30%						6.30%
AEP Texas Inc. [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 117,600,000
Due Date									2025
Interest Rate (Percentage)			2.06%						2.06%
AEP Texas Inc. [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 117,600,000
Due Date									2029
Interest Rate (Percentage)			2.29%						2.29%
AEP Texas Inc. [Member] | Securitization Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 28,200,000
Due Date									2020
Interest Rate (Percentage)			1.98%						1.98%
AEP Texas Inc. [Member] | Securitization Bonds Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 188,000,000
Due Date									2020
Interest Rate (Percentage)			5.31%						5.31%
AEP Texas Inc. [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 300,000,000
Due Date									2049
Interest Rate (Percentage)			4.15%						4.15%
AEP Texas Inc. [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 50,000,000
Due Date									2019
Interest Rate (Percentage)			2.61%						2.61%
AEP Transmission Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,511,900,000						$ 3,511,900,000		2,823,000,000
Long-term Debt Due Within One Year			85,000,000						85,000,000		85,000,000
Long-term Debt			3,426,900,000						3,426,900,000		2,738,000,000
Financing Activities (Textuals)
Sub-Limit of Secured Debt			$ 50,000,000						$ 50,000,000
Maximum Percentage of Consolidated Tangible Net Assets			10.00%						10.00%
Tangible Capital to Tangible Assets			0.10%						0.10%
Maximum Percentage Debt to Capitalization									67.50%
AEP Transmission Co [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 374,900,000
Maximum Loans to Money Pool									244,400,000
Average Borrowings from Money Pool									179,800,000
Average Loans to Money Pool									40,200,000
Net Loans (Borrowings) to/from Money Pool			$ 236,600,000						236,600,000
Authorized Short Term Borrowing Limit	[7]								$ 795,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.72%	2.26%
Average Interest Rate For Funds Loaned									2.57%	2.04%
AEP Transmission Co [Member] | Direct Borrowing [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 1,300,000
Maximum Loans to Money Pool									117,600,000
Average Borrowings from Money Pool									1,300,000
Average Loans to Money Pool									63,400,000
Borrowings from Parent			1,300,000						1,300,000
Loans to Parent			$ 30,800,000						30,800,000
Authorized Short Term Borrowing Limit	[8]								$ 75,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate for Funds Borrowed									3.02%	2.52%
Minimum Interest Rate For Funds Borrowed									2.36%	1.76%
Maximum Interest Rate For Funds Loaned									3.02%	2.52%
Minimum Interest Rate for Funds Loaned									2.36%	1.76%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.70%	2.26%
Average Interest Rate For Funds Loaned									2.70%	2.27%
AEP Transmission Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 350,000,000
Due Date									2049
Interest Rate (Percentage)			3.80%						3.80%
AEP Transmission Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 350,000,000
Due Date									2049
Interest Rate (Percentage)			3.15%						3.15%
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 4,362,900,000						$ 4,362,900,000		4,062,600,000
Long-term Debt Due Within One Year			215,600,000						215,600,000		430,700,000
Long-term Debt			4,147,300,000						4,147,300,000		3,631,900,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									180,400,000	$ 24,000,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			95,400,000						95,400,000		133,300,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			303,300,000			334,100,000			$ 978,500,000	1,079,200,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization									67.50%
Appalachian Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1,200,000			1,800,000			$ 5,800,000	$ 5,100,000
Appalachian Power Co [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 225,400,000
Maximum Loans to Money Pool									232,200,000
Average Borrowings from Money Pool									90,400,000
Average Loans to Money Pool									61,800,000
Net Loans (Borrowings) to/from Money Pool			$ (17,700,000)						(17,700,000)
Authorized Short Term Borrowing Limit									$ 600,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.82%	2.22%
Average Interest Rate For Funds Loaned									2.73%	2.19%
Appalachian Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 86,000,000
Due Date									2024
Interest Rate (Percentage)			2.55%						2.55%
Appalachian Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 86,000,000
Due Date									2019
Interest Rate (Percentage)			1.90%						1.90%
Appalachian Power Co [Member] | Pollution Control Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 70,000,000
Due Date									2019
Interest Rate (Percentage)			3.25%						3.25%
Appalachian Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 24,400,000
Due Date									2023
Interest Rate (Percentage)			2.01%						2.01%
Appalachian Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 400,000,000
Due Date									2049
Interest Rate (Percentage)			4.50%						4.50%
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,031,500,000						$ 3,031,500,000		3,035,400,000
Long-term Debt Due Within One Year			147,400,000						147,400,000		155,400,000
Long-term Debt			2,884,100,000						2,884,100,000		2,880,000,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									73,600,000	$ 856,100,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			156,200,000						156,200,000		152,900,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			485,300,000			498,400,000			1,378,900,000	1,401,700,000
Financing Activities (Textuals)
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			322,000,000						$ 322,000,000		317,000,000
Maximum Percentage Debt to Capitalization									67.50%
Indiana Michigan Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2,400,000			2,500,000			$ 8,400,000	$ 6,800,000
Indiana Michigan Power Co [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 120,400,000
Maximum Loans to Money Pool									66,000,000
Average Borrowings from Money Pool									53,100,000
Average Loans to Money Pool									17,200,000
Net Loans (Borrowings) to/from Money Pool			$ (89,200,000)						(89,200,000)
Authorized Short Term Borrowing Limit									$ 500,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.56%	2.16%
Average Interest Rate For Funds Loaned									2.73%	2.06%
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 62,800,000
Due Date									2023
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt		4,000,000
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 2,700,000
Due Date									2019
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 4,300,000
Due Date									2019
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 13,700,000
Due Date									2020
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 17,900,000
Due Date									2021
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Six [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 11,300,000
Due Date									2022
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Seven [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 16,000,000
Due Date									2022
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Eight [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 6,400,000
Due Date									2023
Interest Rate (Variable)									Variable
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 1,300,000
Due Date									2025
Interest Rate (Percentage)			6.00%						6.00%
Indiana Michigan Power Co [Member] | Pollution Control Bonds [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt		$ 25,000,000
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,113,900,000						$ 2,113,900,000		1,716,600,000
Long-term Debt Due Within One Year			100,000						100,000		47,900,000
Long-term Debt			2,113,800,000						2,113,800,000		1,668,700,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									48,000,000	$ 397,000,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			337,500,000						337,500,000		395,200,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			602,600,000			695,200,000			1,746,100,000	2,046,900,000
Financing Activities (Textuals)
Reacquired Pollution Controls Bonds Held by Trustees			345,000,000						345,000,000
Ohio Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			6,400,000			7,200,000			$ 22,100,000	$ 18,800,000
Ohio Power Co [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 291,200,000
Maximum Loans to Money Pool									178,600,000
Average Borrowings from Money Pool									163,500,000
Average Loans to Money Pool									50,100,000
Net Loans (Borrowings) to/from Money Pool			$ (17,600,000)						(17,600,000)
Authorized Short Term Borrowing Limit									$ 500,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.80%	2.18%
Average Interest Rate For Funds Loaned									2.68%	2.47%
Ohio Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 100,000
Due Date									2028
Interest Rate (Percentage)			1.15%						1.15%
Ohio Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 47,900,000
Due Date									2019
Interest Rate (Percentage)			2.05%						2.05%
Ohio Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 450,000,000
Due Date									2049
Interest Rate (Percentage)			4.00%						4.00%
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,386,400,000						$ 1,386,400,000		1,287,000,000
Long-term Debt Due Within One Year			138,200,000						138,200,000		375,500,000
Long-term Debt			1,248,200,000						1,248,200,000		911,500,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									250,400,000	$ 300,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			149,400,000						149,400,000		109,700,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			451,500,000			454,900,000			$ 1,118,700,000	1,171,200,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization									67.50%
Public Service Co Of Oklahoma [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2,000,000			2,300,000			$ 6,200,000	$ 6,000,000
Public Service Co Of Oklahoma [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 140,500,000
Maximum Loans to Money Pool									215,600,000
Average Borrowings from Money Pool									63,900,000
Average Loans to Money Pool									84,100,000
Net Loans (Borrowings) to/from Money Pool			$ 95,100,000						95,100,000
Authorized Short Term Borrowing Limit									$ 300,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.85%	2.25%
Average Interest Rate For Funds Loaned									2.48%	1.86%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 400,000
Due Date									2027
Interest Rate (Percentage)			3.00%						3.00%
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 100,000,000
Due Date									2029
Interest Rate (Percentage)			3.91%						3.91%
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 150,000,000
Due Date									2034
Interest Rate (Percentage)			4.11%						4.11%
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 100,000,000
Due Date									2049
Interest Rate (Percentage)			4.50%						4.50%
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 250,000,000
Due Date									2019
Interest Rate (Percentage)			5.15%						5.15%
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,656,900,000						$ 2,656,900,000		2,713,400,000
Long-term Debt Due Within One Year			121,200,000						121,200,000		59,700,000
Long-term Debt			2,535,700,000						2,535,700,000		2,653,700,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									58,200,000	$ 385,300,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			168,600,000						168,600,000		$ 150,300,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			480,700,000			512,600,000			$ 1,247,000,000	1,364,600,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization									67.50%
Southwestern Electric Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1,900,000			$ 2,600,000			$ 7,900,000	$ 6,600,000
Southwestern Electric Power Co [Member] | Utility [Member]
Maximum Interest Rate									3.43%	2.52%
Minimum Interest Rate									1.83%	1.81%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool									$ 105,100,000
Maximum Loans to Money Pool									81,400,000
Average Borrowings from Money Pool									57,800,000
Average Loans to Money Pool									11,200,000
Net Loans (Borrowings) to/from Money Pool			6,400,000						6,400,000
Authorized Short Term Borrowing Limit									$ 350,000,000
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed									2.74%	2.31%
Average Interest Rate For Funds Loaned									2.47%	1.87%
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Loans to Money Pool									$ 2,100,000
Average Loans to Money Pool									2,000,000
Net Loans (Borrowings) to/from Money Pool			$ 2,100,000						$ 2,100,000
Maximum and Minimum Interest Rates
Maximum Interest Rate For Funds Loaned									3.02%	2.52%
Minimum Interest Rate for Funds Loaned									2.36%	1.83%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Loaned									2.70%	2.26%
Southwestern Electric Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 3,200,000
Due Date									2032
Interest Rate (Percentage)			4.58%						4.58%
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 1,500,000
Due Date									2028
Interest Rate (Percentage)			4.68%						4.68%
Southwestern Electric Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 53,500,000
Due Date									2019
Interest Rate (Percentage)			1.60%						1.60%
AEP Generating Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 45,000,000
Due Date									2022
Interest Rate (Percentage)			1.35%						1.35%
AEP Generating Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 45,000,000
Due Date									2019
Interest Rate (Variable)									Variable
AEP Energy [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 100,000
Due Date									2019
Interest Rate (Percentage)			5.75%						5.75%
Transource Energy [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]								$ 14,400,000
Due Date									2020
Interest Rate (Variable)									Variable
Transource Energy [Member] | OtherLongTermDebtTwo [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt									$ 1,000,000
Due Date									2020
Interest Rate (Variable)									Varaible
Maximum [Member]
Financing Activities (Textuals)
AEP Share Price for Equity Unit Conversion			$ 99.58						$ 99.58
Shares Per Equity Unit			0.6026						0.6026
Minimum [Member]
Financing Activities (Textuals)
AEP Share Price for Equity Unit Conversion			$ 82.98						$ 82.98
Shares Per Equity Unit			0.5021						0.5021
Retained Earnings [Member]
Financing Activities (Textuals)
Stockholders' Equity, Other									$ 62,000,000
[1]	Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $322 million and $317 million as of September 30, 2019 and December 31, 2018 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
[2]	See “Equity Units” section below for additional information.
[3]	Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
[4]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[5]	Weighted-average rate.
[6]	See “Equity Units” section below for additional information.
[7]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
[8]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

Variable Interest Entities an_4

Variable Interest Entities and Equity Method Investments (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019USD ($)Rate	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)RateMW	Sep. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Securitization Bonds	$ 1,059.4		$ 1,059.4		$ 1,111.4
Securitized Transition Assets	938.7		938.7		920.6
Equity Method Investment Income	15.2	$ 18.1	51.1	$ 55.3
Apple Blossom and Black Oak [Member]
HLBV Income for Noncontrolling Interests	0		(4)
Variable Interest Entities (Textuals) [Abstract]
Noncontrolling Interest	$ 129		$ 129
Santa Rita East [Member]
Percentage of an Asset Acquired | Rate	75.00%		75.00%
Variable Interest Entities (Textuals) [Abstract]
Noncontrolling Interest	$ 118		$ 118
Santa Rita East [Member] | Total Generation MWs [Member]
Wind Generation MWs | MW			302.4
Santa Rita East [Member] | Long-term PPA MWs [Member]
Wind Generation MWs | MW			260
Santa Rita East [Member] | Sold at Wholesale MWs [Member]
Wind Generation MWs | MW			42.4
Santa Rita East [Member] | Consolidated VIE [Member]
Production Tax Credits			$ 8
Current Assets [Member] | Apple Blossom and Black Oak [Member]
Assets [Abstract]
Assets	5.7		5.7
Current Assets [Member] | Santa Rita East [Member]
Assets [Abstract]
Assets	17		17
Current Assets [Member] | Restoration Funding [Member]
Assets [Abstract]
Assets	1.2		1.2
Net Property Plant And Equipment [Member] | Apple Blossom and Black Oak [Member]
Assets [Abstract]
Assets	233.3		233.3
Net Property Plant And Equipment [Member] | Santa Rita East [Member]
Assets [Abstract]
Assets	466.6		466.6
Net Property Plant And Equipment [Member] | Restoration Funding [Member]
Assets [Abstract]
Assets	0		0
Other Noncurrent Assets [Member] | Apple Blossom and Black Oak [Member]
Assets [Abstract]
Assets	12.5		12.5
Other Noncurrent Assets [Member] | Santa Rita East [Member]
Assets [Abstract]
Assets	0.8		0.8
Other Noncurrent Assets [Member] | Restoration Funding [Member]
Assets [Abstract]
Assets	235.3		235.3
Total Assets [Member] | Apple Blossom and Black Oak [Member]
Assets [Abstract]
Assets	251.5		251.5
Total Assets [Member] | Santa Rita East [Member]
Assets [Abstract]
Assets	484.4		484.4
Total Assets [Member] | Restoration Funding [Member]
Assets [Abstract]
Assets	236.5		236.5
Current Liabilities [Member] | Apple Blossom and Black Oak [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	2.2		2.2
Current Liabilities [Member] | Santa Rita East [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	3.5		3.5
Current Liabilities [Member] | Restoration Funding [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	14.4		14.4
Noncurrent Liabilities [Member] | Apple Blossom and Black Oak [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	4.6		4.6
Noncurrent Liabilities [Member] | Santa Rita East [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	7.5		7.5
Noncurrent Liabilities [Member] | Restoration Funding [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	220.9		220.9
Equity [Member] | Apple Blossom and Black Oak [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	244.7		244.7
Equity [Member] | Santa Rita East [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	473.4		473.4
Equity [Member] | Restoration Funding [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	1.2		1.2
Total Liabilities And Equity [Member] | Apple Blossom and Black Oak [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	251.5		251.5
Total Liabilities And Equity [Member] | Santa Rita East [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	484.4		484.4
Total Liabilities And Equity [Member] | Restoration Funding [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity	$ 236.5		$ 236.5
JV Wind Farms [Member]
Equity Method Investment, Ownership Percentage | Rate	50.00%		50.00%
Equity Method Investments	$ 389		$ 389
Historical Investment Balance	417		417
Historical Investment Basis Difference	(19)		(19)
Equity Method Investment Income	(3)		(6)
JV Wind Farms [Member] | Equity Method Investment [Member]
Production Tax Credits	$ 7		$ 21
BP Wind Energy [Member]
Equity Method Investment, Ownership Percentage | Rate	50.00%		50.00%
Berkshire Hathaway Energy [Member]
Equity Method Investment, Ownership Percentage | Rate	50.00%		50.00%
AEP Transmission Holdco [Member]
Equity Method Investment, Ownership Percentage | Rate	49.50%		49.50%
AEP Transmission Partner [Member]
Equity Method Investment, Ownership Percentage | Rate	0.50%		0.50%
ETT [Member]
Equity Method Investment, Ownership Percentage | Rate	50.00%		50.00%
Equity Method Investments	$ 693		$ 693		666
Equity Method Investment Income	16	$ 15	49	$ 46
AEP Texas Inc. [Member]
Securitized Transition Assets	698.1		698.1		$ 649.1
AEP Texas Inc. [Member] | Restoration Funding [Member]
Securitization Bonds	235		235
Securitized Transition Assets	$ 235		$ 235

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2019		Sep. 30, 2018		Sep. 30, 2019		Sep. 30, 2018		Dec. 31, 2018
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		$ 4,315		$ 4,333.1		$ 11,945.4		$ 12,394.6
Revenue Not from Contract with Customer, Other		2.9		6		(58.5)		(28.8)
Total Revenues		4,315		4,333.1		11,945.4		12,394.6
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		908.8				908.8
Revenue Textuals [Abstract]
Revenue from Related Parties		0		0		0		0
2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		252.7				252.7
2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		209.7				209.7
2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		160.9				160.9
2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		285.5				285.5
Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3,278.2		3,372	[1]	9,086.1		9,464.7	[2]
Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,648.2		1,660.9		4,406.7		4,618
Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		903.4		943.7		2,530.6		2,617.9
Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		666.8		707.6		1,979.9		2,057.6
Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		59.8		59.8		168.9		171.2
Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		931		760.5		2,677.5		2,579.1
Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		274.2	[3]	240.8	[4]	838.4	[5]	944.7	[6]
Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		240.9	[7]	120.6	[8]	750.1	[9]	594.2	[10]
Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		415.9		399.1		1,089		1,040.2
Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		102.9	[11]	194.6	[12]	240.3	[13]	379.6	[14]
Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		4,312.1		4,327.1		12,003.9		12,423.4
Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(11.4)	[11]	(52.6)	[15]	(113.1)	[13]	(107.3)	[16]
Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		67.6		55.5		205.3		212.9
Revenue Not from Contract with Customer, Other		14.3	[11]	58.6	[12]	54.6	[13]	78.5	[14]
AEP Texas Inc. [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		41.1		26.1		122.2		61
Total Revenues		489.3		433.4		1,318		1,193.3
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		96.8				96.8
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		17.6				17.6				$ 15
Revenue Textuals [Abstract]
Revenue from Related Parties		42.7		27.5		125.1		63.3
AEP Texas Inc. [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		96.8				96.8
AEP Texas Inc. [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Texas Inc. [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Texas Inc. [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Texas Inc. [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		342.3		326.2	[17]	890.9		880.9	[18]
AEP Texas Inc. [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		192		178.8		454.9		453.6
AEP Texas Inc. [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		110.6		107.9		314.5		310.8
AEP Texas Inc. [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		32.2		32.1		98.8		94.8
AEP Texas Inc. [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		7.5		7.4		22.7		21.7
AEP Texas Inc. [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		97.7		73.6		282		229.6
AEP Texas Inc. [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[19]	0	[20]	0	[21]	0	[22]
AEP Texas Inc. [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		97.7	[23]	73.6	[24]	282	[25]	229.6	[26]
AEP Texas Inc. [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		8.2	[27]	7.5	[28]	22.9	[29]	21.8	[30]
AEP Texas Inc. [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		448.2		407.3		1,195.8		1,132.3
AEP Texas Inc. [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(0.7)	[31]	(1)	[32]	(0.4)	[31]	(1.1)	[33]
AEP Texas Inc. [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.2		1.4		2.6		3
Revenue Not from Contract with Customer, Other		41.8	[31]	27.1	[34]	122.6	[31]	62.1	[35]
AEP Transmission Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(1.2)		(12.4)		(17.8)		(35.4)
Total Revenues		259.7		194.4		770.1		586.2
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		225.8				225.8
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		61.3				61.3				61
Revenue Textuals [Abstract]
Revenue from Related Parties		205.7		148.4		608		453.8
AEP Transmission Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		69.9				69.9				58.6
AEP Transmission Co [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		225.8				225.8
AEP Transmission Co [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Transmission Co [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Transmission Co [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Transmission Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0	[17]	0		0	[18]
AEP Transmission Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		256.4		206.6		775.3		612.9
AEP Transmission Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[19]	0	[20]	0	[21]	0	[22]
AEP Transmission Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		256.4	[23]	206.6	[24]	775.3	[25]	612.9	[26]
Revenue Textuals [Abstract]
Revenue from Related Parties		194		146		587		448
AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		4.5	[27]	0.2	[28]	12.6	[29]	8.7	[30]
AEP Transmission Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		260.9		206.8		787.9		621.6
AEP Transmission Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(1.2)	[31]	(12.4)	[32]	(17.8)	[31]	(35.4)	[33]
AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0.1
Revenue Not from Contract with Customer, Other		0	[31]	0	[34]	0	[31]	0	[35]
Appalachian Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		6.6		(2.1)		11.2		(21.6)
Total Revenues		755.5		762		2,204.1		2,249.4
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		106				106
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		56.4				56.4				73.4
Revenue Textuals [Abstract]
Revenue from Related Parties		56.6		42.9		154.6		138.7
Appalachian Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		41.4				41.4				52.5
Appalachian Power Co [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		36.4				36.4
Appalachian Power Co [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		32.5				32.5
Appalachian Power Co [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		25.5				25.5
Appalachian Power Co [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		11.6				11.6
Appalachian Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		633.6		652.8	[17]	1,867		1,974.5	[18]
Appalachian Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		315.7		320.9		944.7		1,017.3
Appalachian Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		147.2		155.1		421.5		442.3
Appalachian Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		152.2		157.6		444.3		457.3
Appalachian Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		18.5		19.2		56.5		57.6
Appalachian Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		96.6		95.4		277.7		254.3
Appalachian Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		70.4	[19]	74.5	[20]	200.1	[21]	194.1	[22]
Revenue Textuals [Abstract]
Revenue from Related Parties		32		30		96		100
Appalachian Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		26.2	[23]	20.9	[24]	77.6	[25]	60.2	[26]
Appalachian Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		18.7	[27]	15.9	[28]	48.2	[29]	42.2	[30]
Appalachian Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		748.9		764.1		2,192.9		2,271
Appalachian Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		6.6	[31]	(1.2)	[32]	11.2	[31]	(20.7)	[33]
Appalachian Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.2		2.3		8.2		7.6
Revenue Not from Contract with Customer, Other		0	[31]	(0.9)	[34]	0	[31]	(0.9)	[35]
Indiana Michigan Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(1.1)		10.2		(1.4)		(4)
Total Revenues		611.1		629.7		1,768.5		1,796.2
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		29.3				29.3
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		45.3				45.3				75
Revenue Textuals [Abstract]
Revenue from Related Parties		2.7		3.4		7.3		18.9
Indiana Michigan Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		28				28				35.3
Indiana Michigan Power Co [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		7.2				7.2
Indiana Michigan Power Co [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		8.9				8.9
Indiana Michigan Power Co [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		8.8				8.8
Indiana Michigan Power Co [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		4.4				4.4
Indiana Michigan Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		477.1		497.3	[17]	1,347.5		1,362.6	[18]
Indiana Michigan Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		198.2		207.4		558.8		559.4
Indiana Michigan Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		138.3		138		371.4		369.8
Indiana Michigan Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		138.7		150.2		411.9		428
Indiana Michigan Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.9		1.7		5.4		5.4
Indiana Michigan Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		108.5		99.8		346.2		366.6
Indiana Michigan Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		102.1	[19]	93.6	[20]	327.4	[21]	349.7	[22]
Indiana Michigan Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		6.4	[23]	6.2	[24]	18.8	[25]	16.9	[26]
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		26.6	[27]	22.4	[28]	76.2	[29]	71	[30]
Indiana Michigan Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		612.2		619.5		1,769.9		1,800.2
Indiana Michigan Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(1.1)	[31]	1.5	[32]	(1.4)	[31]	(4)	[33]
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3.1		2.7		7.6		10.1
Revenue Not from Contract with Customer, Other		0	[31]	8.7	[34]	0	[31]	0	[35]
Revenue Textuals [Abstract]
Revenue from Related Parties		20		17		57		57
Ohio Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		9.6		37.4		25.8		35.1
Total Revenues		710.6		778.3		2,154		2,318
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		25.3				25.3
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		56.2				56.2				70.8
Revenue Textuals [Abstract]
Revenue from Related Parties		9		3.3		18.2		17.9
Ohio Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		29.2				29.2				46.1
Ohio Power Co [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		17.8				17.8
Ohio Power Co [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		7.5				7.5
Ohio Power Co [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Ohio Power Co [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Ohio Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		646.3		756	[17]	1,972.9		2,188.8	[18]
Ohio Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		395.6		433.5		1,155.5		1,258.4
Ohio Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		180.5		222.9		573.7		633.2
Ohio Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		67.1		96.3		233.9		287.4
Ohio Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3.1		3.3		9.8		9.8
Ohio Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		13.7		14.8		42		42.8
Ohio Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[19]	0	[20]	0	[21]	0	[22]
Ohio Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		13.7	[23]	14.8	[24]	42	[25]	42.8	[26]
Ohio Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		41	[27]	(29.9)	[28]	113.3	[29]	51.3	[30]
Ohio Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		701		740.9		2,128.2		2,282.9
Ohio Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		12.4	[31]	(36.9)	[32]	22	[31]	(47.2)	[33]
Ohio Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3		2.4		8.4		5.3
Revenue Not from Contract with Customer, Other		(2.8)	[31]	74.3	[34]	3.8	[31]	82.3	[35]
Public Service Co Of Oklahoma [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		7.1		2.3		(25.3)		11.2
Total Revenues		493		481.4		1,173.9		1,216.5
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		4.3				4.3
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		27.3				27.3				26.2
Revenue Textuals [Abstract]
Revenue from Related Parties		1.3		1.1		5		3.7
Public Service Co Of Oklahoma [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		10.3				10.3				12.4
Public Service Co Of Oklahoma [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		4.3				4.3
Public Service Co Of Oklahoma [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Public Service Co Of Oklahoma [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Public Service Co Of Oklahoma [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Public Service Co Of Oklahoma [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		463.1		447.6	[17]	1,125.1		1,134.6	[18]
Public Service Co Of Oklahoma [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		231.9		220.8		519.6		531.4
Public Service Co Of Oklahoma [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		122.2		119.9		304.3		309.3
Public Service Co Of Oklahoma [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		84.1		82.4		238.1		228.7
Public Service Co Of Oklahoma [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		24.9		24.5		63.1		65.2
Public Service Co Of Oklahoma [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		17.7		26		57.4		56.1
Public Service Co Of Oklahoma [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		21.1	[19]	12.5	[20]	35.5	[21]	26.7	[22]
Public Service Co Of Oklahoma [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(3.4)	[23]	13.5	[24]	21.9	[25]	29.4	[26]
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		5.1	[27]	5.5	[28]	16.7	[29]	14.6	[30]
Public Service Co Of Oklahoma [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		485.9		479.1		1,199.2		1,205.3
Public Service Co Of Oklahoma [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		7.1	[31]	2.3	[32]	(25.3)	[31]	11.2	[33]
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.2		1.2		4.6		3.3
Revenue Not from Contract with Customer, Other		0	[31]	0	[34]	0	[31]	0	[35]
Southwestern Electric Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(4)		(0.3)		(47.4)		2.3
Total Revenues		545.5		535.3		1,342.1		1,411.8
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		9.8				9.8
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		56.8				56.8				28.8
Revenue Textuals [Abstract]
Revenue from Related Parties		8.8		8.7		21.6		20.2
Southwestern Electric Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		17.8				17.8				$ 16.3
Southwestern Electric Power Co [Member] | 2019 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		9.8				9.8
Southwestern Electric Power Co [Member] | 2020-2021 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Southwestern Electric Power Co [Member] | 2022-2023 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Southwestern Electric Power Co [Member] | 2023 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Southwestern Electric Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		461.8		446.3	[17]	1,138.7		1,145.4	[18]
Southwestern Electric Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		222.9		214.1		503.7		512.4
Southwestern Electric Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		144.3		140.4		371.1		372.6
Southwestern Electric Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		92.3		89.6		257.2		254
Southwestern Electric Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.3		2.2		6.7		6.4
Southwestern Electric Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		80.7		82.7		230.7		246.1
Southwestern Electric Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		50.7	[19]	53.2	[20]	152.7	[21]	168.8	[22]
Southwestern Electric Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		30	[23]	29.5	[24]	78	[25]	77.3	[26]
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		7	[27]	6.6	[28]	20.1	[29]	18	[30]
Southwestern Electric Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		549.5		535.6		1,389.5		1,409.5
Southwestern Electric Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(4)	[31]	(0.3)	[32]	(47.4)	[31]	2.3	[33]
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.3		0.6		1		1.2
Revenue Not from Contract with Customer, Other		0	[31]	0	[34]	0	[31]	0	[35]
Consolidation Eliminations [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Revenue Not from Contract with Customer, Other		(56.6)		43		(169.5)		0
Total Revenues		(348.2)		(247.6)		(991.7)		(674.1)
Revenue Textuals [Abstract]
Revenue from Related Parties		(348.2)		(247.6)		(991.7)		(674.1)
Consolidation Eliminations [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.5		0	[1]	0		0	[2]
Consolidation Eliminations [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Consolidation Eliminations [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Consolidation Eliminations [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.5		0		0		0
Consolidation Eliminations [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Consolidation Eliminations [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(250.9)		(340.1)		(708.6)		(675.9)
Consolidation Eliminations [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(34.2)	[3]	(98.5)	[4]	(105.5)	[5]	(155.2)	[6]
Consolidation Eliminations [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(217.2)	[7]	(241.6)	[8]	(603.6)	[9]	(520.7)	[10]
Consolidation Eliminations [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.5		0		0.5		0
Consolidation Eliminations [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(42.2)	[11]	49.5	[12]	(113.6)	[13]	1.8	[14]
Consolidation Eliminations [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(291.6)		(290.6)		(822.2)		(674.1)
Consolidation Eliminations [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(16.8)	[11]	0	[15]	(60.3)	[13]	0	[16]
Consolidation Eliminations [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(39.8)	[11]	43	[12]	(109.2)	[13]	0	[14]
Consolidation Eliminations [Member] | AEP Transmission Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Total Revenues		0		0		0		0
Revenue Textuals [Abstract]
Revenue from Related Parties		0		0		0		0
Consolidation Eliminations [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Vertically Integrated Utilities [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		1.2		10		(55.7)		(18.1)
Total Revenues		2,645.5		2,636.7		7,172.6		7,393.7
Revenue Textuals [Abstract]
Revenue from Related Parties		46.6		26.5		85		61.3
Vertically Integrated Utilities [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2,287.9		2,289.4	[1]	6,222.2		6,395.1	[2]
Vertically Integrated Utilities [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,060.2		1,048.7		2,797.6		2,906.9
Vertically Integrated Utilities [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		612.5		612.8		1,641.2		1,672.7
Vertically Integrated Utilities [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		566		578.8		1,647.3		1,676.1
Vertically Integrated Utilities [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		49.2		49.1		136.1		139.4
Vertically Integrated Utilities [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		309.1		297		877.3		894.9
Vertically Integrated Utilities [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		231.3	[3]	224.2	[4]	661.9	[5]	686.5	[6]
Vertically Integrated Utilities [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		77.8	[7]	72.8	[8]	215.4	[9]	208.4	[10]
Vertically Integrated Utilities [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		47.3	[11]	40.3	[12]	128.8	[13]	121.8	[14]
Vertically Integrated Utilities [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2,644.3		2,626.7		7,228.3		7,411.8
Vertically Integrated Utilities [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		1.2	[11]	0.2	[15]	(55.7)	[13]	(19.2)	[16]
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0	[11]	9.8	[12]	0	[13]	1.1	[14]
Transmission And Distribution Utilities [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		44		(29)		138.8		3.6
Total Revenues		1,186.6		1,211.5		3,454.3		3,510.9
Revenue Textuals [Abstract]
Revenue from Related Parties		39.3		30.6		125.6		60.9
Transmission And Distribution Utilities [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		988.8		1,082.6	[1]	2,863.9		3,069.6	[2]
Transmission And Distribution Utilities [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		588		612.2		1,609.1		1,711.1
Transmission And Distribution Utilities [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		290.9		330.9		889.4		945.2
Transmission And Distribution Utilities [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		99.3		128.8		332.6		381.5
Transmission And Distribution Utilities [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		10.6		10.7		32.8		31.8
Transmission And Distribution Utilities [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		110.9		88		324		272.6
Transmission And Distribution Utilities [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[3]	0	[4]	0	[5]	0	[6]
Transmission And Distribution Utilities [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		110.9	[7]	88	[8]	324	[9]	272.6	[10]
Transmission And Distribution Utilities [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		42.9	[11]	69.9	[12]	127.6	[13]	165.1	[14]
Transmission And Distribution Utilities [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,142.6		1,240.5		3,315.5		3,507.3
Transmission And Distribution Utilities [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		5.1	[11]	(37.9)	[15]	21.5	[13]	(48.3)	[16]
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		38.9	[11]	8.9	[12]	117.3	[13]	51.9	[14]
AEP Transmission Holdco [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(0.9)		(14.9)		(18.6)		(39.8)
Total Revenues		273		187.2		808.3		605.2
AEP Transmission Holdco [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0	[1]	0		0	[2]
AEP Transmission Holdco [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Holdco [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Holdco [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Holdco [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Holdco [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		269.4		201.4		814.3		633.9
AEP Transmission Holdco [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[3]	0	[4]	0	[5]	0	[6]
AEP Transmission Holdco [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		269.4	[7]	201.4	[8]	814.3	[9]	633.9	[10]
Revenue Textuals [Abstract]
Revenue from Related Parties		197		147		596		444
AEP Transmission Holdco [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
AEP Transmission Holdco [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		4.5	[11]	0.7	[12]	12.6	[13]	11.1	[14]
AEP Transmission Holdco [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		273.9		202.1		826.9		645
AEP Transmission Holdco [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(0.9)	[11]	(14.9)	[15]	(18.6)	[13]	(39.8)	[16]
AEP Transmission Holdco [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0	[11]	0	[12]	0	[13]	0	[14]
Generation And Marketing [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		26.4		(5.3)		53.2		18.8
Total Revenues		533.7		521.6		1,428.2		1,487.4
Revenue Textuals [Abstract]
Revenue from Related Parties		32.5		35.1		104.4		88.1
Generation And Marketing [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0	[1]	0		0	[2]
Generation And Marketing [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Generation And Marketing [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Generation And Marketing [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Generation And Marketing [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Generation And Marketing [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		492.5		514.2		1,370.5		1,453.6
Generation And Marketing [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		77.1	[3]	115.1	[4]	282	[5]	413.4	[6]
Revenue Textuals [Abstract]
Revenue from Related Parties		34		35		105		87
Generation And Marketing [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[7]	0	[8]	0	[9]	0	[10]
Generation And Marketing [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		415.4		399.1		1,088.5		1,040.2
Generation And Marketing [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		14.8	[11]	12.7	[12]	4.5	[13]	15	[14]
Generation And Marketing [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		507.3		526.9		1,375		1,468.6
Generation And Marketing [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0	[11]	0	[15]	0	[13]	0	[16]
Generation And Marketing [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		26.4	[11]	(5.3)	[12]	53.2	[13]	18.8	[14]
Other Segments [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(11.2)		2.2		(6.7)		6.7
Total Revenues	[36]	24.4		23.7		73.7		71.5
Revenue Textuals [Abstract]
Revenue from Related Parties	[36]	22.3		20.1		64.9		55.1
Other Segments [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0	[1]	0		0	[2]
Other Segments [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Other Segments [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Other Segments [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Other Segments [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Other Segments [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Other Segments [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[3]	0	[4]	0	[5]	0	[6]
Other Segments [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[7]	0	[8]	0	[9]	0	[10]
Other Segments [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Other Segments [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		35.6	[11]	21.5	[12]	80.4	[13]	64.8	[14]
Other Segments [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		35.6		21.5		80.4		64.8
Other Segments [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0	[11]	0	[15]	0	[13]	0	[16]
Other Segments [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[36]	2.1		3.6		8.8		16.4
Revenue Not from Contract with Customer, Other		$ (11.2)	[11]	$ 2.2	[12]	$ (6.7)	[13]	$ 6.7	[14]
[1]	2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
[2]	2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
[3]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million . The remaining affiliated amounts were immaterial.
[4]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million . The remaining affiliated amounts were immaterial.
[5]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million . The remaining affiliated amounts were immaterial.
[6]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $87 million
[7]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million . The remaining affiliated amounts were immaterial.
[8]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $147 million . The remaining affiliated amounts were immaterial.
[9]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million . The remaining affiliated amounts were immaterial.
[10]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $444 million . The remaining affiliated amounts were immaterial.
[11]	Amounts include affiliated and nonaffiliated revenues.
[12]	Amounts include affiliated and nonaffiliated revenues.
[13]	Amounts include affiliated and nonaffiliated revenues.
[14]	Amounts include affiliated and nonaffiliated revenues.
[15]	The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million
[16]	The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement.
[17]	2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
[18]	2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
[19]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[20]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[21]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[22]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
[23]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $194 million . The remaining affiliated amounts were immaterial.
[24]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $146 million . The remaining affiliated amounts were immaterial.
[25]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $587 million . The remaining affiliated amounts were immaterial.
[26]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $448 million . The remaining affiliated amounts were immaterial.
[27]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
[28]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
[29]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
[30]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
[31]	Amounts include affiliated and nonaffiliated revenues.
[32]	The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement.
[33]	The alternative revenue for OPCo was primarily the $48 million
[34]	Amounts include affiliated and nonaffiliated revenues.
[35]	Amounts include affiliated and nonaffiliated revenues.
[36]	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.