Appalachian Power 10-Q 25 Oct 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 25, 2018
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		493,108,827
AEP Texas Inc. [Member]
Entity Registrant Name	AEP Texas Inc.
Entity Central Index Key	1,721,781
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		100
AEP Transmission Co [Member]
Entity Registrant Name	AEP Transmission Company, LLC
Entity Central Index Key	1,702,494
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Appalachian Power Co [Member]
Entity Registrant Name	APPALACHIAN POWER CO
Entity Central Index Key	6,879
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		13,499,500
Indiana Michigan Power Co [Member]
Entity Registrant Name	INDIANA MICHIGAN POWER CO
Entity Central Index Key	50,172
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,400,000
Ohio Power Co [Member]
Entity Registrant Name	OHIO POWER CO
Entity Central Index Key	73,986
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		27,952,473
Public Service Co Of Oklahoma [Member]
Entity Registrant Name	PUBLIC SERVICE CO OF OKLAHOMA
Entity Central Index Key	81,027
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		9,013,000
Southwestern Electric Power Co [Member]
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER CO
Entity Central Index Key	92,487
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		7,536,640

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2018		Sep. 30, 2017
Revenues
Revenue from Contracts with Customers		$ 4,333.1		$ 4,104.7		$ 12,394.6		$ 11,614.5
Sales to AEP Affiliates		0		0		0		0
TOTAL REVENUES		4,333.1		4,104.7		12,394.6		11,614.5
Expenses
Other Operation		826		644		2,332.7		1,884.1
Maintenance		316.6		269		911		862.6
Gain on Sale of Merchant Generation Assets		0		0		0		(226.4)
Depreciation and Amortization		602.6		518.5		1,695.5		1,485.9
Taxes Other Than Income Taxes		294.2		272.6		863		792
TOTAL EXPENSES		3,664.5		3,129.6		10,263		8,820.4
OPERATING INCOME (LOSS)		668.6		975.1		2,131.6		2,794.1
Other Income (Expense):
Interest and Investment Income		5.4		2.4		11.3		12.7
Carrying Costs Income		0.9		2.6		7.2		14.2
Allowance for Equity Funds Used During Construction		30.9		20		92.4		62.2
Non-Service Cost Components of Net Periodic Benefit Cost		31.9		11.4		95.3		34.2
Gain (Loss) on Disposition of Stock in Subsidiary or Equity Method Investee		0		12.4		0		12.4
Interest Expense		(256.8)		(223.3)		(733.1)		(668)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		480.9		800.6		1,604.7		2,261.8
Income Tax Expense (Credit)		(80.7)		264		93.5		797.8
Equity Earnings (Loss) of Unconsolidated Subsidiaries		18.1		20.1		55.3		63.1
Net Income (Loss)		579.7		556.7		1,566.5		1,527.1
Net Income Attributable to Noncontrolling Interests		2.1		12		6.1		15.2
Earnings Attributable to Common Shareholders		$ 577.6		$ 544.7		$ 1,560.4		$ 1,511.9
Earnings Per Share
Weighted Average Number of Basic AEP Common Shares Outstanding		492,984,741		491,840,722		492,649,456		491,781,643
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations		$ 1.17		$ 1.11		$ 3.17		$ 3.07
Total Basic Earnings Per Share Attributable to AEP Common Shareholders		$ 1.17		$ 1.11		$ 3.17		$ 3.07
Weighted Average Number of Diluted AEP Common Shares Outstanding		493,940,543		492,986,307		493,526,937		492,428,586
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations		$ 1.17		$ 1.10		$ 3.16		$ 3.07
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders		1.17		1.10		3.16		3.07
Common Stock, Dividends Per Share, Declared		$ 0.62		$ 0.59		$ 1.86		$ 1.77
Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		$ 2,610.2		$ 2,453.8		$ 7,332.4		$ 6,819.3
Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers		1,180.9		1,149.7		3,450		3,242.7
Generation and Marketing [Member]
Revenues
Revenue from Contracts with Customers		486.5		441.5		1,399.3		1,386.8
Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		55.5		59.7		212.9		165.7
TOTAL REVENUES		58.6	[1]			78.5	[2]
Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		240.8	[3]			944.7	[4]
Expenses
Cost of Goods and Services Sold		840.4		707.4		1,909.1		1,865.3
Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		784.7		718.1		2,551.7		2,156.9
AEP Texas Inc. [Member]
Revenues
Revenue from Contracts with Customers		407.3
Sales to AEP Affiliates		27.5		18.9		63.3		50.8
TOTAL REVENUES		433.4		431.2		1,193.3		1,164.3
Expenses
Other Operation		133.4		117.5		368.4		332.8
Maintenance		23.2		19.3		67.8		58.1
Depreciation and Amortization		133.3		124		364.9		343
Taxes Other Than Income Taxes		36.3		33.3		102.3		93.3
TOTAL EXPENSES		339.4		302.4		931.3		844.4
OPERATING INCOME (LOSS)		94		128.8		262		319.9
Other Income (Expense):
Interest Income		0.5		0.5		0		1.6
Allowance for Equity Funds Used During Construction		5.8		0		15.2		2.2
Non-Service Cost Components of Net Periodic Benefit Cost		3.1		0.9		9.2		2.7
Interest Expense		(37.3)		(35.3)		(108.9)		(105.6)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		66.1		94.9		177.5		220.8
Income Tax Expense (Credit)		8.3		30.6		26.4		74.2
Net Income (Loss)		57.8		64.3		151.1		146.6
AEP Texas Inc. [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers		404.5		411.5		1,127		1,111.4
AEP Texas Inc. [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		1.4		0.8		3		2.1
TOTAL REVENUES		27.1	[5]			62.1	[6]
AEP Texas Inc. [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		0	[7]			0	[8]
Expenses
Cost of Goods and Services Sold		13.2		8.3		27.9		17.2
AEP Transmission Co [Member]
Revenues
Revenue from Contracts with Customers	[9]	206.8
Sales to AEP Affiliates		148.4		130.1	[10]	453.8	[10]	439.1	[10]
TOTAL REVENUES		194.4	[9]	165.6	[10]	586.2	[9],[10]	534.8	[10]
Expenses
Other Operation		24.5		18.4		59.6		38.8
Maintenance		2.8		1.4		7.6		6.8
Depreciation and Amortization		34.9		24.6		97.5		69.7
Taxes Other Than Income Taxes		35.2		27.6		102.9		82
TOTAL EXPENSES		97.4		72		267.6		197.3
OPERATING INCOME (LOSS)		97		93.6		318.6		337.5
Other Income (Expense):
Interest Income		0.5		0.2	[10]	1.3	[10]	0.5	[10]
Allowance for Equity Funds Used During Construction		18		11.4		48.7		33
Interest Expense		(19.8)		(17.1)	[10]	(60.7)	[10]	(50.4)	[10]
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		95.7		88.1		307.9		320.6
Income Tax Expense (Credit)		17.6		29.5	[10]	63.7	[10]	108.2	[10]
Net Income (Loss)		78.1		58.6	[10]	244.2	[10]	212.4	[10]
AEP Transmission Co [Member] | Transmission [Member]
Revenues
Revenue from Contracts with Customers		46		35.6	[10]	132.3	[10]	95.7	[10]
AEP Transmission Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		0		(0.1)	[10]	0.1	[10]	0	[10]
TOTAL REVENUES	[9]	0	[5]			0	[6]
AEP Transmission Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	[9]	0	[7]			0	[8]
Appalachian Power Co [Member]
Revenues
Revenue from Contracts with Customers		764.1
Sales to AEP Affiliates		42.9		41.9		138.7		130.6
TOTAL REVENUES		762		719.3		2,249.4		2,187.4
Expenses
Other Operation		131.9		117		380		370.1
Maintenance		97.2		55.8		234.9		187.8
Depreciation and Amortization		105.7		102.8		319.5		304.1
Taxes Other Than Income Taxes		33.6		32.3		101.1		93.3
TOTAL EXPENSES		712.2		547.6		1,874		1,670.7
OPERATING INCOME (LOSS)		49.8		171.7		375.4		516.7
Other Income (Expense):
Interest Income		0.4		0.3		1.3		1.1
Carrying Costs Income		0.2		0.4		1.2		1
Allowance for Equity Funds Used During Construction		4.1		2.7		9.6		6.2
Non-Service Cost Components of Net Periodic Benefit Cost		4.5		1.3		13.4		3.9
Interest Expense		(50.8)		(47.2)		(146)		(143.5)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		8.2		129.2		254.9		385.4
Income Tax Expense (Credit)		(78.9)		43.2		(35.1)		136.7
Net Income (Loss)		87.1		86		290		248.7
Appalachian Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		716.8		674.4		2,103.1		2,045
Appalachian Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		2.3		3		7.6		11.8
TOTAL REVENUES		(0.9)	[5]			(0.9)	[6]
Appalachian Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		74.5	[7]			194.1	[8]
Sales to AEP Affiliates		30				100
Expenses
Cost of Goods and Services Sold		263.4		178.6		487.7		498.3
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		80.4		61.1		350.8		217.1
Indiana Michigan Power Co [Member]
Revenues
Revenue from Contracts with Customers		619.5
Other Revenues - Affiliated		17.1		17.1		62.2		48.2
TOTAL REVENUES		629.7		557.7		1,796.2		1,585.5
Expenses
Purchased Electricity from AEP Affiliates		60		62.4		181.8		166.2
Other Operation		149.3		142		425.8		438.8
Maintenance		57.2		51.5		169.1		153.6
Depreciation and Amortization		85.2		55		207.1		154.8
Taxes Other Than Income Taxes		23		23.9		72.9		68.3
TOTAL EXPENSES		519.5		444.1		1,471.2		1,321.1
OPERATING INCOME (LOSS)		110.2		113.6		325		264.4
Other Income (Expense):
Interest Income		1.6		0.2		2.8		1.6
Carrying Costs Income		0.6		2.2		4.6		9.9
Allowance for Equity Funds Used During Construction		3.9		3.5		8		8.1
Non-Service Cost Components of Net Periodic Benefit Cost		4.6		1.5		13.6		4.6
Interest Expense		(34.5)		(27.5)		(95.6)		(83)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		86.4		93.5		258.4		205.6
Income Tax Expense (Credit)		13.7		28.6		26.8		61.8
Net Income (Loss)		72.7		64.9		231.6		143.8
Indiana Michigan Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		609.9		537		1,723.9		1,527.4
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		2.7		3.6		10.1		9.9
Sales to AEP Affiliates		17				57
TOTAL REVENUES		8.7	[5]			0	[6]
Indiana Michigan Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		93.6	[7]			349.7	[8]
Expenses
Cost of Goods and Services Sold		95.9		76.4		246.8		238.2
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		48.9		32.9		167.7		101.2
Ohio Power Co [Member]
Revenues
Revenue from Contracts with Customers		740.9
Sales to AEP Affiliates		3.3		4.6		17.9		19.4
TOTAL REVENUES		778.3		742		2,318		2,152
Expenses
Purchased Electricity from AEP Affiliates		39.3		26.7		97.4		83.4
Amortization of Generation Deferrals		56.9		58.7		171.9		172.9
Other Operation		215.2		126.9		586.4		380.9
Maintenance		43.4		37.9		114.7		108.4
Depreciation and Amortization		70.4		57.3		200.3		165.7
Taxes Other Than Income Taxes		106.9		100.4		311		293.8
TOTAL EXPENSES		698.4		588.6		2,016.4		1,730.5
OPERATING INCOME (LOSS)		79.9		153.4		301.6		421.5
Other Income (Expense):
Interest Income		0.8		0.7		2.6		4
Carrying Costs Income		0.2		0.5		1.5		3
Allowance for Equity Funds Used During Construction		2		0.9		7.8		4.1
Non-Service Cost Components of Net Periodic Benefit Cost		3.8		1.1		11.6		3.3
Interest Expense		(26.1)		(25.7)		(76.6)		(76.8)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		60.6		130.9		248.5		359.1
Income Tax Expense (Credit)		(28.1)		48.3		11.4		128
Net Income (Loss)		88.7		82.6		237.1		231.1
Ohio Power Co [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers		772.6		736		2,294.8		2,127.8
Ohio Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		2.4		1.4		5.3		4.8
TOTAL REVENUES		74.3	[5]			82.3	[6]
Ohio Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		0	[7]			0	[8]
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		166.3		180.7		534.7		525.4
Public Service Co Of Oklahoma [Member]
Revenues
Revenue from Contracts with Customers		479.1
Sales to AEP Affiliates		1.1		1.1		3.7		3.2
TOTAL REVENUES		481.4		442.8		1,216.5		1,091.6
Expenses
Other Operation		106.3		84.5		286.8		228.9
Maintenance		22.3		25.2		73.2		88.2
Depreciation and Amortization		42.3		31.7		120.5		97.8
Taxes Other Than Income Taxes		10.8		9.8		32.6		30
TOTAL EXPENSES		402.9		356.9		1,076.9		940.5
OPERATING INCOME (LOSS)		78.5		85.9		139.6		151.1
Other Income (Expense):
Allowance for Equity Funds Used During Construction						(0.3)		0.4
Other Income		(0.2)		0		(0.3)		0.5
Non-Service Cost Components of Net Periodic Benefit Cost		2.1		0.9		6.5		2.6
Interest Expense		(16.4)		(13.2)		(47.4)		(40.2)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		64		73.6		98.4		114
Income Tax Expense (Credit)		3.6		27.4		8.6		42.6
Net Income (Loss)		60.4		46.2		89.8		71.4
Public Service Co Of Oklahoma [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		479.1		440.6		1,209.5		1,085.1
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		1.2		1.1		3.3		3.3
TOTAL REVENUES		0	[5]			0	[6]
Public Service Co Of Oklahoma [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		12.5	[7]			26.7	[8]
Expenses
Cost of Goods and Services Sold		104.4		77.9		211.5		115.8
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		116.8		127.8		352.3		379.8
Southwestern Electric Power Co [Member]
Revenues
Revenue from Contracts with Customers		535.6
Sales to AEP Affiliates		8.7		7.7		20.2		20.4
TOTAL REVENUES		535.3		517.6		1,411.8		1,343.6
Expenses
Other Operation		99.1		81.2		292		234.9
Maintenance		33.6		32.6		102.2		106.5
Depreciation and Amortization		59.9		55.2		175.9		158.1
Taxes Other Than Income Taxes		26.9		25.1		76.4		72.7
TOTAL EXPENSES		408.2		381.6		1,172.6		1,080.7
OPERATING INCOME (LOSS)		127.1		136		239.2		262.9
Other Income (Expense):
Interest Income		1.1		0.7		3.5		2
Allowance for Equity Funds Used During Construction		0.6		0.4		3.8		1.2
Non-Service Cost Components of Net Periodic Benefit Cost		2.3		1		6.9		2.8
Interest Expense		(32.7)		(31.9)		(95.8)		(92.7)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		98.4		106.2		157.6		176.2
Income Tax Expense (Credit)		9.6		22.5		17.9		45.2
Equity Earnings (Loss) of Unconsolidated Subsidiaries		0.8		0.4		2		(4.5)
Net Income (Loss)		89.6		84.1		141.7		126.5
Net Income Attributable to Noncontrolling Interests		1.4		11		4.1		12.6
Earnings Attributable to Common Shareholders		88.2		73.1		137.6		113.9
Southwestern Electric Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers		526		509.5		1,390.4		1,321.8
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers		0.6		0.4		1.2		1.4
TOTAL REVENUES		0	[5]			0	[6]
Southwestern Electric Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers		53.2	[7]			168.8	[8]
Expenses
Cost of Goods and Services Sold		152.1		147.5		393.4		389.8
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold		$ 36.6		$ 40		$ 132.7		$ 118.7
[1]	Amounts include affiliated and nonaffiliated revenues.
[2]	Amounts include affiliated and nonaffiliated revenues.
[3]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $35 million. The remaining affiliated amounts are immaterial.
[4]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $87 million. The remaining affiliated amounts are immaterial.
[5]	Amounts include affiliated and nonaffiliated revenues.
[6]	Amounts include affiliated and nonaffiliated revenues.
[7]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.
[8]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.
[9]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[10]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income (Loss)	$ 579.7	$ 556.7	$ 1,566.5	$ 1,527.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	10.2	(15)	14.7	(22.6)
Securities Available for Sale, Net of Tax	0	0.9	0	2.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1.4)	0.3	(4)	0.8
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	8.8	(13.8)	10.7	(19.1)
TOTAL COMPREHENSIVE INCOME (LOSS)	588.5	542.9	1,577.2	1,508
Total Comprehensive Income Attributable to Noncontrolling Interest	2.1	12	6.1	15.2
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	586.4	530.9	1,571.1	1,492.8
AEP Texas Inc. [Member]
Net Income (Loss)	57.8	64.3	151.1	146.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.3	0.2	0.8	0.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0	0.1	0.1	0.2
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.3	0.9	0.9
TOTAL COMPREHENSIVE INCOME (LOSS)	58.1	64.6	152	147.5
Appalachian Power Co [Member]
Net Income (Loss)	87.1	86	290	248.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.3)	(0.1)	(0.7)	(0.5)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.7)	(0.3)	(2.3)	(0.9)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1)	(0.4)	(3)	(1.4)
TOTAL COMPREHENSIVE INCOME (LOSS)	86.1	85.6	287	247.3
Indiana Michigan Power Co [Member]
Net Income (Loss)	72.7	64.9	231.6	143.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.3	0.3	1.2	1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.3	1.2	1
TOTAL COMPREHENSIVE INCOME (LOSS)	73	65.2	232.8	144.8
Ohio Power Co [Member]
Net Income (Loss)	88.7	82.6	237.1	231.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.4)	(0.3)	(1)	(0.8)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(1)	(0.8)
TOTAL COMPREHENSIVE INCOME (LOSS)	88.3	82.3	236.1	230.3
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	60.4	46.2	89.8	71.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.2)	(0.7)	(0.6)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(0.7)	(0.6)
TOTAL COMPREHENSIVE INCOME (LOSS)	60.2	46	89.1	70.8
Southwestern Electric Power Co [Member]
Net Income (Loss)	89.6	84.1	141.7	126.5
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	2.7	0.4	3.6	1.1
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.3)	(0.2)	(1)	(0.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	2.4	0.2	2.6	0.6
TOTAL COMPREHENSIVE INCOME (LOSS)	92	84.3	144.3	127.1
Total Comprehensive Income Attributable to Noncontrolling Interest	1.4	11	4.1	12.6
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 90.6	$ 73.3	$ 140.2	$ 114.5

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Cash Flow Hedges, Tax	$ 2.7	$ (8.1)	$ 3.9	$ (12.2)
Securities Available for Sale, Tax	0	0.5	0	1.5
Amortization of Pension and OPEB Deferred Costs, Tax	(0.4)	0.1	(11.1)	0.4
AEP Texas Inc. [Member]
Cash Flow Hedges, Tax	0.1	0.2	0.2	0.4
Amortization of Pension and OPEB Deferred Costs, Tax	0	0	0	0.1
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.2)	(0.3)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.2)	(0.1)	(0.6)	(0.4)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.1	0.3	0.5
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.3)	(0.4)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	0	(0.1)	(0.2)	(0.3)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.8	0.2	1	0.6
Amortization of Pension and OPEB Deferred Costs, Tax	$ (0.1)	$ (0.1)	$ (0.3)	$ (0.3)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	AEP Texas Inc. [Member]	AEP Transmission Co [Member]		Appalachian Power Co [Member]	Indiana Michigan Power Co [Member]	Ohio Power Co [Member]	Public Service Co Of Oklahoma [Member]	Southwestern Electric Power Co [Member]	Common Stock [Member]	Common Stock [Member]Appalachian Power Co [Member]	Common Stock [Member]Indiana Michigan Power Co [Member]	Common Stock [Member]Ohio Power Co [Member]	Common Stock [Member]Public Service Co Of Oklahoma [Member]	Common Stock [Member]Southwestern Electric Power Co [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]AEP Texas Inc. [Member]	Additional Paid-in Capital [Member]AEP Transmission Co [Member]	Additional Paid-in Capital [Member]Appalachian Power Co [Member]	Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member]	Additional Paid-in Capital [Member]Ohio Power Co [Member]	Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member]	Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member]	Retained Earnings [Member]	Retained Earnings [Member]AEP Texas Inc. [Member]	Retained Earnings [Member]AEP Transmission Co [Member]	Retained Earnings [Member]Appalachian Power Co [Member]	Retained Earnings [Member]Indiana Michigan Power Co [Member]	Retained Earnings [Member]Ohio Power Co [Member]	Retained Earnings [Member]Public Service Co Of Oklahoma [Member]	Retained Earnings [Member]Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]		Accumulated Other Comprehensive Income [Member]AEP Texas Inc. [Member]		Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member]		Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member]		Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member]	Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member]	Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member]		Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Southwestern Electric Power Co [Member]
Beginning Balance at Dec. 31, 2016			$ 1,957.6															$ 1,455								$ 502.6
Beginning Balance at Dec. 31, 2016	$ 17,420.1	$ 1,657.1			$ 3,583.5	$ 2,151.8	$ 2,117.5	$ 1,214.1	$ 2,215.2	$ 3,328.3	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,332.6	$ 857.9		$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 7,892.4	$ 814.1		$ 1,502.8	$ 1,130.5	$ 954.5	$ 689.5	$ 1,411.9	$ (156.3)		$ (14.9)		$ (8.4)		$ (16.2)		$ 3	$ 3.4	$ (9.4)		$ 23.1	$ 0.4
Beginning Balance, Shares at Dec. 31, 2016										512,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock Dividends	(875)																							(872.3)
Common Stock Dividends					(90)	(93.7)	(130)	(52.5)	(82.5)																		(90)	(93.7)	(130)	(52.5)	(82.5)
Common Stock Dividends									(2.7)																																			(2.7)	(2.7)
Other Changes in Equity	52.4															51.6																												0.8
Capital Contribution from Member		200	185.5														200	185.5
Net Income (Loss)	1,511.9								113.9															1,511.9							113.9
Net Income Attributable to Noncontrolling Interests	15.2								12.6																																			15.2	12.6
Net Income (Loss)	1,527.1	146.6	212.4	[1]	248.7	143.8	231.1	71.4	126.5																146.6	212.4	248.7	143.8	231.1	71.4
Other Comprehensive Income (Loss)	(19.1)	0.9			(1.4)	1	(0.8)	(0.6)	0.6																							(19.1)		0.9		(1.4)		1		(0.8)	(0.6)	0.6
Ending Balance at Sep. 30, 2017			2,355.5															1,640.5								715
Ending Balance at Sep. 30, 2017	18,105.5	2,004.6			3,740.8	2,202.9	2,217.8	1,232.4	2,257.1	$ 3,328.3	260.4	56.6	321.2	157.2	135.7	6,384.2	1,057.9		1,828.7	980.9	838.8	364	676.6	8,532	960.7		1,661.5	1,180.6	1,055.6	708.4	1,443.3	(175.4)		(14)		(9.8)		(15.2)		2.2	2.8	(8.8)		36.4	10.3
Ending Balance, Shares at Sep. 30, 2017										512,000,000
Beginning Balance at Dec. 31, 2017			2,589.9															1,816.6								773.3
Beginning Balance at Dec. 31, 2017	$ 18,313.6	2,169.9			3,804.5	2,217.6	2,310.3	$ 1,215.3	2,234.5	$ 3,329.4	260.4	56.6	321.2	157.2	135.7	6,398.7	1,057.9		1,828.7	980.9	838.8	364	676.6	8,626.7	1,124.6		1,714.1	1,192.2	1,148.4	691.5	1,426.6	(67.8)		(12.6)		1.3		(12.1)		1.9	2.6	(4)		26.6	(0.4)
Beginning Balance, Shares at Dec. 31, 2017	512,210,644							10,482,000		512,200,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	$ 62.5									$ 7.1						55.4
Issuance of Common Stock, Shares										1,100,000
Common Stock Dividends	(922.5)																							(919.3)
Common Stock Dividends					(120)	(105.5)	(337.5)	$ (37.5)	(60)																		(120)	(105.5)	(337.5)	(37.5)	(60)
Common Stock Dividends									(3.2)																																			(3.2)	(3.2)
Other Changes in Equity	19															18.5																												0.5
Capital Contribution from Member		100	582														100	582
ASU 2018-02 Adoption	(3)	(0.9)			0.4	(2.4)	0.4	0.5	(1.3)															14	1.8		0.1	0.3			(0.4)	(17)	[2]	(2.7)	[2]	0.3	[2]	(2.7)	[2]	0.4	0.5	(0.9)	[2]
ASU 2016-01 Adoption	0																							11.9								(11.9)	[2]
Net Income (Loss)	1,560.4								137.6															1,560.4							137.6
Net Income Attributable to Noncontrolling Interests	6.1								4.1																																			6.1	4.1
Net Income (Loss)	1,566.5	151.1	244.2	[1]	290	231.6	237.1	89.8	141.7																151.1	244.2	290	231.6	237.1	89.8
Other Comprehensive Income (Loss)	10.7	0.9			(3)	1.2	(1)	(0.7)	2.6																							10.7		0.9		(3)		1.2		(1)	(0.7)	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	$ 2,421			$ 3,971.9	$ 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	$ 1,157.9		$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 9,293.7	$ 1,277.5		$ 1,884.2	$ 1,318.6	$ 1,048	$ 743.8	$ 1,503.8	$ (86)		$ (14.4)		$ (1.4)		$ (13.6)		$ 1.3	$ 2.4	$ (2.3)		$ 30	$ 0.5
Ending Balance, Shares at Sep. 30, 2018	513,301,636							10,482,000		513,300,000
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[2]	See Note 2 - New Accounting Pronouncements for additional information.

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents		$ 788.3	$ 214.6
Restricted Cash		149.2	198
Other Temporary Investments		164.1	161.7
Accounts Receivable:
Customers		757.9	643.9
Accrued Unbilled Revenues		241.2	230.2
Pledged Accounts Receivable - AEP Credit		1,112.2	954.2
Miscellaneous		47.2	101.2
Allowance for Uncollectible Accounts		(40.4)	(38.5)
Total Accounts Receivable		2,118.1	1,891
Fuel		282.3	387.7
Materials and Supplies		565.6	565.5
Risk Management Assets		191.9	126.2
Regulatory Asset for Under-Recovered Fuel Costs		137.5	292.5
Margin Deposits		108.8	105.5
Prepayments and Other Current Assets		186.6	310.4
TOTAL CURRENT ASSETS		4,692.4	4,253.1
Property, Plant and Equipment
Generation		21,327.3	20,760.5
Transmission		20,113.7	18,972.5
Distribution		20,763.9	19,868.5
Other Property, Plant and Equipment		3,996.9	3,706.3
Construction Work in Progress		4,995.5	4,120.7
Total Property, Plant and Equipment		71,197.3	67,428.5
Accumulated Depreciation and Amortization		17,841.6	17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		53,355.7	50,261.5
Other Noncurrent Assets
Regulatory Assets		3,189.9	3,587.6
Securitized Assets		1,001.4	1,211.2
Spent Nuclear Fuel and Decommissioning Trusts		2,666	2,527.6
Goodwill		52.5	52.5
Long-term Risk Management Assets		264.9	282.1
Deferred Charges and Other Noncurrent Assets		2,394.6	2,553.5
TOTAL OTHER NONCURRENT ASSETS		9,569.3	10,214.5
TOTAL ASSETS		67,617.4	64,729.1
Current Liabilities
Accounts Payable		1,579.9	2,065.3
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	750	718
Other Short-term Debt		1,492.6	920.6
Total Short-term Debt		2,242.6	1,638.6
Long-term Debt Due Within One Year		1,904.2	1,753.7
Risk Management Liabilities		57.3	61.6
Customer Deposits		372.5	357
Accrued Taxes		774.1	1,115.5
Accrued Interest		299.8	234.5
Regulatory Liability for Over-Recovered Fuel Costs		66.9	11.9
Other Current Liabilities		1,128.9	1,033.2
TOTAL CURRENT LIABILITIES		8,426.2	8,271.3
Noncurrent Liabilities
Long-term Debt		20,869.8	19,419.6
Long-term Risk Management Liabilities		287.2	322
Deferred Income Taxes		7,110.4	6,813.9
Regulatory Liabilities and Deferred Investment Tax Credits		8,643.5	8,422.3
Asset Retirement Obligations		1,975.1	1,925.5
Employee Benefits and Pension Obligations		350.7	398.1
Deferred Credits and Other Noncurrent Liabilities		807.2	830.9
TOTAL NONCURRENT LIABILITIES		40,043.9	38,132.3
TOTAL LIABILITIES		48,470.1	46,403.6
Rate Matters
Commitments and Contingencies
Redeemable Noncontrolling Interest		70	0
Contingently Reedemable Performance Share Awards		30.5	11.9
Total Mezzanine Equity		100.5	11.9
Equity
Common Stock		3,336.5	3,329.4
Paid-in Capital		6,472.6	6,398.7
Retained Earnings		9,293.7	8,626.7
Accumulated Other Comprehensive Income (Loss)		(86)	(67.8)
TOTAL COMMON SHAREHOLDER'S EQUITY		19,016.8	18,287
Noncontrolling Interests		30	26.6
TOTAL EQUITY		19,046.8	18,313.6
TOTAL LIABILITIES AND EQUITY		67,617.4	64,729.1
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents		0.1	2
Restricted Cash		124.2	155.2
Advances to Affiliates		8	111.9
Accounts Receivable:
Customers		132.9	105.3
Affiliated Companies		14.3	12.3
Accrued Unbilled Revenues		73.7	75.8
Miscellaneous		0.5	1.3
Allowance for Uncollectible Accounts		(0.9)	(0.7)
Total Accounts Receivable		220.5	194
Fuel		6.9	3.6
Materials and Supplies		51.1	52
Risk Management Assets		0.5	0.5
Accrued Tax Benefits		14.6	41
Prepayments and Other Current Assets		12	3.6
TOTAL CURRENT ASSETS		437.9	563.8
Property, Plant and Equipment
Generation		352.1	350.7
Transmission		3,302.3	3,053.6
Distribution		3,968.4	3,718.6
Other Property, Plant and Equipment		554	461
Construction Work in Progress		1,108.8	835.7
Total Property, Plant and Equipment		9,285.6	8,419.6
Accumulated Depreciation and Amortization		1,643.9	1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,641.7	6,825.1
Other Noncurrent Assets
Regulatory Assets		396.4	378.7
Securitized Assets		717.9	891.2
Deferred Charges and Other Noncurrent Assets		97.8	114.8
TOTAL OTHER NONCURRENT ASSETS		1,212.1	1,384.7
TOTAL ASSETS		9,291.7	8,773.6
Current Liabilities
Advances from Affiliates		77.8	0
Accounts Payable		208.8	379.4
Affiliated Companies		31.7	30.2
Short-term Debt:
Long-term Debt Due Within One Year		500.5	266.1
Accrued Taxes		90.8	77.2
Accrued Interest		54.3	42.2
Oklaunion Purchase Power Agreement		22.8	0
Other Current Liabilities		99.5	76.4
TOTAL CURRENT LIABILITIES		1,086.2	871.5
Noncurrent Liabilities
Long-term Debt		3,413.9	3,383.2
Deferred Income Taxes		902.3	913.1
Regulatory Liabilities and Deferred Investment Tax Credits		1,346.4	1,320.5
Oklaunion Purchase Power Agreement		28.7	52
Deferred Credits and Other Noncurrent Liabilities		93.2	63.4
TOTAL NONCURRENT LIABILITIES		5,784.5	5,732.2
TOTAL LIABILITIES		6,870.7	6,603.7
Rate Matters
Commitments and Contingencies
Equity
Paid-in Capital		1,157.9	1,057.9
Retained Earnings		1,277.5	1,124.6
Accumulated Other Comprehensive Income (Loss)		(14.4)	(12.6)
TOTAL EQUITY		2,421	2,169.9
TOTAL LIABILITIES AND EQUITY		9,291.7	8,773.6
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0	0
Advances to Affiliates		278	146.3
Accounts Receivable:
Customers		11.9	15
Affiliated Companies		73	93.2
Miscellaneous		1.1	1.3
Total Accounts Receivable		86	109.5
Materials and Supplies		16.4	13.6
Accrued Tax Benefits		29.8	49.4
Prepayments and Other Current Assets		3.5	7.6
TOTAL CURRENT ASSETS		413.7	326.4
Property, Plant and Equipment
Transmission		5,833.5	5,319.7
Other Property, Plant and Equipment		155.2	126.8
Construction Work in Progress		1,772.9	1,324
Total Property, Plant and Equipment	[2]	7,761.6	6,770.5
Accumulated Depreciation and Amortization	[2]	234.6	152.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[2]	7,527	6,617.9
Other Noncurrent Assets
Regulatory Assets		15.3	11.7
Deferred Property Taxes		38.1	125
Deferred Charges and Other Noncurrent Assets		4.3	1.1
TOTAL OTHER NONCURRENT ASSETS		57.7	137.8
TOTAL ASSETS	[2]	7,998.4	7,082.1
Current Liabilities
Advances from Affiliates		1.1	15.7
Accounts Payable		237.4	484.5
Affiliated Companies		79	66.1
Short-term Debt:
Long-term Debt Due Within One Year		50	50
Accrued Taxes		138.7	231.5
Accrued Interest		35.9	15
Other Current Liabilities		4.3	4.1
TOTAL CURRENT LIABILITIES		546.4	866.9
Noncurrent Liabilities
Long-term Debt		2,822.6	2,500.4
Deferred Income Taxes		684.4	600.4
Regulatory Liabilities and Deferred Investment Tax Credits		509.6	493.8
Deferred Credits and Other Noncurrent Liabilities		19.3	30.7
TOTAL NONCURRENT LIABILITIES		4,035.9	3,625.3
TOTAL LIABILITIES		4,582.3	4,492.2
Rate Matters
Commitments and Contingencies
Equity
Paid-in Captial		2,398.6	1,816.6
Retained Earnings		1,017.5	773.3
TOTAL MEMBER'S EQUITY		3,416.1	2,589.9
TOTAL LIABILITIES AND EQUITY		7,998.4	7,082.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.2	2.9
Restricted Cash		9.9	16.3
Advances to Affiliates		23.1	23.5
Accounts Receivable:
Customers		155.7	123.1
Affiliated Companies		70.6	69.3
Accrued Unbilled Revenues		52.6	74.1
Miscellaneous		0.9	1.1
Allowance for Uncollectible Accounts		(4)	(3.7)
Total Accounts Receivable		275.8	263.9
Fuel		37.7	89.3
Materials and Supplies		98.4	99.5
Risk Management Assets		68.4	24.9
Regulatory Asset for Under-Recovered Fuel Costs		79.9	88.8
Margin Deposits		12.5	14.4
Prepayments and Other Current Assets		23	12.7
TOTAL CURRENT ASSETS		630.9	636.2
Property, Plant and Equipment
Generation		6,490	6,446.9
Transmission		3,141.2	3,019.9
Distribution		3,897.2	3,763.8
Other Property, Plant and Equipment		461.4	427.9
Construction Work in Progress		602.1	483
Total Property, Plant and Equipment		14,591.9	14,141.5
Accumulated Depreciation and Amortization		4,086.2	3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,505.7	10,245.1
Other Noncurrent Assets
Regulatory Assets		475.3	573.9
Securitized Assets		264.5	282.3
Long-term Risk Management Assets		1.4	1.1
Deferred Charges and Other Noncurrent Assets		180.1	190
TOTAL OTHER NONCURRENT ASSETS		921.3	1,047.3
TOTAL ASSETS		12,057.9	11,928.6
Current Liabilities
Advances from Affiliates		98.5	186
Accounts Payable		219.1	264.9
Affiliated Companies		73.6	92.7
Short-term Debt:
Long-term Debt Due Within One Year		430.7	249.2
Risk Management Liabilities		0.9	1.3
Customer Deposits		88	86.1
Accrued Taxes		81.5	94.5
Accrued Interest		72.6	40.5
Other Current Liabilities		151.6	109
TOTAL CURRENT LIABILITIES		1,216.5	1,124.2
Noncurrent Liabilities
Long-term Debt		3,631	3,730.9
Long-term Risk Management Liabilities		0.7	0.2
Deferred Income Taxes		1,581.5	1,565.7
Regulatory Liabilities and Deferred Investment Tax Credits		1,423.8	1,454.9
Asset Retirement Obligations		103.2	100.2
Employee Benefits and Pension Obligations		65.7	73.3
Deferred Credits and Other Noncurrent Liabilities		63.6	74.7
TOTAL NONCURRENT LIABILITIES		6,869.5	6,999.9
TOTAL LIABILITIES		8,086	8,124.1
Rate Matters
Commitments and Contingencies
Equity
Common Stock		260.4	260.4
Paid-in Capital		1,828.7	1,828.7
Retained Earnings		1,884.2	1,714.1
Accumulated Other Comprehensive Income (Loss)		(1.4)	1.3
TOTAL EQUITY		3,971.9	3,804.5
TOTAL LIABILITIES AND EQUITY		12,057.9	11,928.6
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.6	1.3
Advances to Affiliates		72.5	12.4
Accounts Receivable:
Customers		70.5	56.4
Affiliated Companies		51.7	50
Accrued Unbilled Revenues		16.1	7.3
Miscellaneous		1.9	2
Allowance for Uncollectible Accounts		(0.2)	(0.1)
Total Accounts Receivable		140	115.6
Fuel		28.7	31.4
Materials and Supplies		165.7	160.6
Risk Management Assets		10.9	7.6
Accrued Tax Benefits		35.4	58.4
Regulatory Asset for Under-Recovered Fuel Costs		0.1	15
Accrued Reimbursement of Spent Nuclear Fuel Costs		7.9	10.8
Prepayments and Other Current Assets		20.9	20.9
TOTAL CURRENT ASSETS		483.7	434
Property, Plant and Equipment
Generation		4,579.9	4,445.9
Transmission		1,543.3	1,504
Distribution		2,183.9	2,069.3
Other Property, Plant and Equipment		584.7	595.2
Construction Work in Progress		458.6	460.2
Total Property, Plant and Equipment		9,350.4	9,074.6
Accumulated Depreciation and Amortization		3,113.9	3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,236.5	6,050.4
Other Noncurrent Assets
Regulatory Assets		545.3	579.4
Spent Nuclear Fuel and Decommissioning Trusts		2,666	2,527.6
Long-term Risk Management Assets		0.9	0.7
Deferred Charges and Other Noncurrent Assets		175.7	179.9
TOTAL OTHER NONCURRENT ASSETS		3,387.9	3,287.6
TOTAL ASSETS		10,108.1	9,772
Current Liabilities
Advances from Affiliates		0	211.6
Accounts Payable		142.6	154.5
Affiliated Companies		65.6	98.3
Short-term Debt:
Long-term Debt Due Within One Year		172.7	474.7
Risk Management Liabilities		6.4	3.5
Customer Deposits		37	37.7
Accrued Taxes		44.7	81.3
Accrued Interest		22.2	37.5
Other Current Liabilities		129.8	112.2
TOTAL CURRENT LIABILITIES		621	1,211.3
Noncurrent Liabilities
Long-term Debt		2,889.7	2,270.4
Long-term Risk Management Liabilities		0.4	0.1
Deferred Income Taxes		1,010	953.8
Regulatory Liabilities and Deferred Investment Tax Credits		1,791.9	1,708.7
Asset Retirement Obligations		1,365.1	1,321.6
Deferred Credits and Other Noncurrent Liabilities		87.5	88.5
TOTAL NONCURRENT LIABILITIES		7,144.6	6,343.1
TOTAL LIABILITIES		7,765.6	7,554.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,318.6	1,192.2
Accumulated Other Comprehensive Income (Loss)		(13.6)	(12.1)
TOTAL EQUITY		2,342.5	2,217.6
TOTAL LIABILITIES AND EQUITY		10,108.1	9,772
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.5	3.1
Restricted Cash		15.2	26.6
Accounts Receivable:
Customers		116.9	67.8
Affiliated Companies		72.4	70.2
Accrued Unbilled Revenues		32.7	29.7
Miscellaneous		0.9	1.9
Allowance for Uncollectible Accounts		(1.4)	(0.6)
Total Accounts Receivable		221.5	169
Materials and Supplies		38.5	41.9
Renewable Energy Credits		23	25
Risk Management Assets		0.6	0.6
Regulatory Asset for Under-Recovered Fuel Costs		34.1	115.9
Prepayments and Other Current Assets		16.7	15.8
TOTAL CURRENT ASSETS		353.1	397.9
Property, Plant and Equipment
Transmission		2,484.5	2,419.2
Distribution		4,825.6	4,626.4
Other Property, Plant and Equipment		547.5	495.9
Construction Work in Progress		475.7	410.1
Total Property, Plant and Equipment		8,333.3	7,951.6
Accumulated Depreciation and Amortization		2,230.6	2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,102.7	5,766.8
Other Noncurrent Assets
Regulatory Assets		389.1	652.8
Securitized Assets		19	37.7
Long-term Risk Management Assets		0.1	0
Deferred Charges and Other Noncurrent Assets		254.6	406.5
TOTAL OTHER NONCURRENT ASSETS		662.8	1,097
TOTAL ASSETS		7,118.6	7,261.7
Current Liabilities
Advances from Affiliates		242.9	87.8
Accounts Payable		169.2	205.8
Affiliated Companies		95.3	118.2
Short-term Debt:
Long-term Debt Due Within One Year		47.8	397
Risk Management Liabilities		5.4	6.4
Customer Deposits		77.5	69.2
Accrued Taxes		293.8	512.5
Other Current Liabilities		205.9	196.9
TOTAL CURRENT LIABILITIES		1,137.8	1,593.8
Noncurrent Liabilities
Long-term Debt		1,668.5	1,322.3
Long-term Risk Management Liabilities		89.8	126
Deferred Income Taxes		742.8	762.9
Regulatory Liabilities and Deferred Investment Tax Credits		1,197.7	1,100.2
Deferred Credits and Other Noncurrent Liabilities		72.7	46.2
TOTAL NONCURRENT LIABILITIES		3,771.5	3,357.6
TOTAL LIABILITIES		4,909.3	4,951.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		1,048	1,148.4
Accumulated Other Comprehensive Income (Loss)		1.3	1.9
TOTAL EQUITY		2,209.3	2,310.3
TOTAL LIABILITIES AND EQUITY		7,118.6	7,261.7
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1.9	1.6
Accounts Receivable:
Customers		28.8	32.5
Affiliated Companies		39.8	32.9
Miscellaneous		4.4	4.1
Allowance for Uncollectible Accounts		(0.2)	(0.1)
Total Accounts Receivable		72.8	69.4
Fuel		12.6	12.5
Materials and Supplies		43.4	42
Risk Management Assets		18.5	6.4
Accrued Tax Benefits		12.5	28.1
Regulatory Asset for Under-Recovered Fuel Costs		0	36.7
Prepayments and Other Current Assets		8.1	8.6
TOTAL CURRENT ASSETS		169.8	205.3
Property, Plant and Equipment
Generation		1,576.3	1,577.2
Transmission		881.5	858.8
Distribution		2,543.1	2,445.1
Other Property, Plant and Equipment		308.3	287.4
Construction Work in Progress		85.7	111.3
Total Property, Plant and Equipment		5,394.9	5,279.8
Accumulated Depreciation and Amortization		1,461.2	1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,933.7	3,886.2
Other Noncurrent Assets
Regulatory Assets		352.1	368.1
Employee Benefits and Pension Assets		41.3	40
Deferred Charges and Other Noncurrent Assets		16.6	8.7
TOTAL OTHER NONCURRENT ASSETS		410	416.8
TOTAL ASSETS		4,513.5	4,508.3
Current Liabilities
Advances from Affiliates		22	149.6
Accounts Payable		113	102.4
Affiliated Companies		42.2	48
Short-term Debt:
Long-term Debt Due Within One Year		0.5	0.5
Risk Management Liabilities		0.6	0
Customer Deposits		56.1	54.1
Accrued Taxes		40.5	22.6
Accrued Interest		18.9	14.1
Regulatory Liability for Over-Recovered Fuel Costs		36	0
Other Current Liabilities		56.5	44.7
TOTAL CURRENT LIABILITIES		386.3	436
Noncurrent Liabilities
Long-term Debt		1,286.4	1,286
Deferred Income Taxes		636.6	642
Regulatory Liabilities and Deferred Investment Tax Credits		850.3	853.5
Asset Retirement Obligations		54.8	53
Deferred Credits and Other Noncurrent Liabilities		31.7	22.5
TOTAL NONCURRENT LIABILITIES		2,859.8	2,857
TOTAL LIABILITIES		3,246.1	3,293
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		743.8	691.5
Accumulated Other Comprehensive Income (Loss)		2.4	2.6
TOTAL EQUITY		1,267.4	1,215.3
TOTAL LIABILITIES AND EQUITY		4,513.5	4,508.3
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.5	1.6
Advances to Affiliates		518.6	2
Accounts Receivable:
Customers		29.1	70.9
Affiliated Companies		32.8	30.2
Miscellaneous		20.9	25.8
Allowance for Uncollectible Accounts		(0.9)	(1.3)
Total Accounts Receivable		81.9	125.6
Fuel		117.5	123.6
Materials and Supplies		69	67.9
Risk Management Assets		6.5	6.4
Regulatory Asset for Under-Recovered Fuel Costs		14.5	14.1
Prepayments and Other Current Assets		32	39.2
TOTAL CURRENT ASSETS		842.5	380.4
Property, Plant and Equipment
Generation		4,655.6	4,624.9
Transmission		1,812	1,679.8
Distribution		2,146.4	2,095.8
Other Property, Plant and Equipment		744.4	684.1
Construction Work in Progress		234.5	233.2
Total Property, Plant and Equipment		9,592.9	9,317.8
Accumulated Depreciation and Amortization		2,798.9	2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,794	6,632
Other Noncurrent Assets
Regulatory Assets		217.8	220.6
Deferred Charges and Other Noncurrent Assets		133.1	109.9
TOTAL OTHER NONCURRENT ASSETS		350.9	330.5
TOTAL ASSETS		7,987.4	7,342.9
Current Liabilities
Advances from Affiliates		0	118.7
Accounts Payable		117.6	160.4
Affiliated Companies		41.3	63.7
Short-term Debt:
Other Short-term Debt		19.4	22
Long-term Debt Due Within One Year		457.2	3.7
Risk Management Liabilities		0.2	0.2
Customer Deposits		62.7	62.1
Accrued Taxes		75.2	39
Accrued Interest		27.5	38.9
Obligations Under Capital Leases		10.8	11.2
Other Current Liabilities		101.6	78.7
TOTAL CURRENT LIABILITIES		913.5	598.6
Noncurrent Liabilities
Long-term Debt		2,615.5	2,438.2
Long-term Risk Management Liabilities		2.6	0
Deferred Income Taxes		932.9	917.7
Regulatory Liabilities and Deferred Investment Tax Credits		896.7	896.4
Asset Retirement Obligations		179.3	160.3
Employee Benefits and Pension Obligations		19.3	19.5
Obligations Under Capital Leases		52.8	57.8
Deferred Credits and Other Noncurrent Liabilities		60.5	19.9
TOTAL NONCURRENT LIABILITIES		4,759.6	4,509.8
TOTAL LIABILITIES		5,673.1	5,108.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,503.8	1,426.6
Accumulated Other Comprehensive Income (Loss)		(2.3)	(4)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,313.8	2,234.9
Noncontrolling Interests		0.5	(0.4)
TOTAL EQUITY		2,314.3	2,234.5
TOTAL LIABILITIES AND EQUITY		$ 7,987.4	$ 7,342.9
[1]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 788.3	$ 214.6
Restricted Cash	149.2	198
Other Temporary Investments	164.1	161.7
Fuel	282.3	387.7
Property, Plant and Equipment
Other Property, Plant and Equipment	3,996.9	3,706.3
Accumulated Depreciation and Amortization	17,841.6	17,167
Other Noncurrent Assets
Securitized Transition Assets	1,001.4	1,211.2
Current Liabilities
Long-term Debt Due Within One Year	1,904.2	1,753.7
Accrued Interest	299.8	234.5
Noncurrent Liabilities
Long-term Debt	$ 20,869.8	$ 19,419.6
Equity
Common Stock, Par Value Per Share	$ 6.50	$ 6.50
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	513,301,636	512,210,644
Treasury Stock, Shares	20,204,160	20,205,046
AEP Subsidiaries [Member]
Current Assets
Restricted Cash	$ 149.2	$ 198
Other Temporary Investments	157	155.4
Current Liabilities
Long-term Debt Due Within One Year	420.7	406.9
Noncurrent Liabilities
Long-term Debt	1,110	1,410.5
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents	0.1	2
Restricted Cash	124.2	155.2
Fuel	6.9	3.6
Property, Plant and Equipment
Other Property, Plant and Equipment	554	461
Accumulated Depreciation and Amortization	1,643.9	1,594.5
Other Noncurrent Assets
Securitized Transition Assets	717.9	891.2
Current Liabilities
Long-term Debt Due Within One Year	500.5	266.1
Accrued Interest	54.3	42.2
Noncurrent Liabilities
Long-term Debt	3,413.9	3,383.2
AEP Texas Inc. [Member] | AEP Texas Central Transition Funding Co [Member]
Other Noncurrent Assets
Securitized Transition Assets	702.9	869.5
Current Liabilities
Long-term Debt Due Within One Year	250.5	236.1
Accrued Interest	9	15.9
Noncurrent Liabilities
Long-term Debt	574.7	790.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	2.2	2.9
Restricted Cash	9.9	16.3
Fuel	37.7	89.3
Property, Plant and Equipment
Other Property, Plant and Equipment	461.4	427.9
Accumulated Depreciation and Amortization	4,086.2	3,896.4
Other Noncurrent Assets
Securitized Transition Assets	264.5	282.3
Current Liabilities
Long-term Debt Due Within One Year	430.7	249.2
Accrued Interest	72.6	40.5
Noncurrent Liabilities
Long-term Debt	$ 3,631	$ 3,730.9
Equity
Common Stock, Shares Authorized	30,000,000	30,000,000
Common Stock, Shares Outstanding	13,499,500	13,499,500
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 1.6	$ 1.3
Fuel	28.7	31.4
Property, Plant and Equipment
Other Property, Plant and Equipment	584.7	595.2
Accumulated Depreciation and Amortization	3,113.9	3,024.2
Current Liabilities
Long-term Debt Due Within One Year	172.7	474.7
Accrued Interest	22.2	37.5
Noncurrent Liabilities
Long-term Debt	$ 2,889.7	$ 2,270.4
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	2,500,000	2,500,000
Common Stock, Shares Outstanding	1,400,000	1,400,000
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 94.2	$ 96.3
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3.5	3.1
Restricted Cash	15.2	26.6
Property, Plant and Equipment
Other Property, Plant and Equipment	547.5	495.9
Accumulated Depreciation and Amortization	2,230.6	2,184.8
Other Noncurrent Assets
Securitized Transition Assets	19	37.7
Current Liabilities
Long-term Debt Due Within One Year	47.8	397
Noncurrent Liabilities
Long-term Debt	$ 1,668.5	$ 1,322.3
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 47.7	$ 47
Noncurrent Liabilities
Long-term Debt	0	47.5
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	1.9	1.6
Fuel	12.6	12.5
Property, Plant and Equipment
Other Property, Plant and Equipment	308.3	287.4
Accumulated Depreciation and Amortization	1,461.2	1,393.6
Current Liabilities
Long-term Debt Due Within One Year	0.5	0.5
Accrued Interest	18.9	14.1
Noncurrent Liabilities
Long-term Debt	$ 1,286.4	$ 1,286
Equity
Common Stock, Par Value Per Share	$ 15	$ 15
Common Stock, Shares Authorized	11,000,000	11,000,000
Common Stock, Shares, Issued	10,482,000	10,482,000
Common Stock, Shares Outstanding	9,013,000	9,013,000
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 2.5	$ 1.6
Fuel	117.5	123.6
Property, Plant and Equipment
Other Property, Plant and Equipment	744.4	684.1
Accumulated Depreciation and Amortization	2,798.9	2,685.8
Current Liabilities
Long-term Debt Due Within One Year	457.2	3.7
Accrued Interest	27.5	38.9
Noncurrent Liabilities
Long-term Debt	$ 2,615.5	$ 2,438.2
Equity
Common Stock, Par Value Per Share	$ 18	$ 18
Common Stock, Shares Authorized	7,600,000	7,600,000
Common Stock, Shares Outstanding	7,536,640	7,536,640
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Current Assets
Fuel	$ 33.4	$ 41.5
Property, Plant and Equipment
Other Property, Plant and Equipment	269.6	266.7
Accumulated Depreciation and Amortization	$ 174.7	$ 165.9

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net Income (Loss)		$ 1,566.5	$ 1,527.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		1,695.5	1,485.9
Deferred Income Taxes		43	740.9
Carrying Costs Income		(7.2)	(14.2)
Allowance for Equity Funds Used During Construction		(92.4)	(62.2)
Mark-to-Market of Risk Management Contracts		(95.4)	(56.2)
Amortization of Nuclear Fuel		82.6	104.8
Pension Contributions to Qualified Plan Trust		0	(93.3)
Property Taxes		304.8	291.4
Deferred Fuel Over/Under-Recovery, Net		210.6	81
Gain on Sale of Merchant Generation Assets		0	(226.4)
Gain (Loss) on Disposition of Stock in Subsidiary or Equity Method Investee		0	(12.4)
Recovery of Ohio Capacity Costs, Net		52.7	65.6
Provision for Refund - Global Settlement		(5.5)	(93.3)
Change in Other Noncurrent Assets		161.6	(334.6)
Change in Other Noncurrent Liabilities		141.9	205.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(52.3)	201.3
Fuel, Materials and Supplies		98.7	58.5
Accounts Payable		(45)	(91)
Accrued Taxes, Net		(247.5)	(310.1)
Other Current Assets		11.7	(98.2)
Other Current Liabilities		101.1	(260.3)
Net Cash Flows from (Used for) Operating Activities		3,932.6	3,124.2
Investing Activities
Construction Expenditures		(4,688.4)	(3,778.2)
Purchases of Investment Securities		(1,591.2)	(1,855.8)
Sales of Investment Securities		1,550.9	1,808.6
Acquisitions of Nuclear Fuel		(26.1)	(73.2)
Proceeds From Sale Of Merchant Generation Assets		0	2,159.6
Other Investing Activities		66.1	16.3
Net Cash Flows from (Used for) Investing Activities		(4,688.7)	(1,722.7)
Financing Activities
Issuance of Common Stock, Net		62.5	0
Issuance of Long-term Debt		3,572	2,742.7
Commercial Paper and Credit Facility Borrowings		205.6	0
Change in Short-term Debt, Net		604	(653.7)
Retirement of Long-term Debt		(1,959.5)	(2,427.2)
Commercial Paper and Credit Facility Repayments		(205.6)	0
Make Whole Premium on Extinguishment of Long-term Debt		(10.3)	(46.1)
Principal Payments for Capital Lease Obligations		(49.4)	(50.5)
Dividends Paid on Common Stock		(922.5)	(875)
Other Financing Activities		(15.8)	(4.4)
Net Cash Flows from (Used for) Financing Activities		1,281	(1,314.2)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		524.9	87.3
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		412.6	403.5
Cash and Cash Equivalents at Beginning of Period		214.6
Cash, Cash Equivalents and Restricted Cash at End of Period		937.5	490.8
Cash and Cash Equivalents at End of Period		788.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		631.3	613.8
Net Cash Paid (Received) for Income Taxes		(27.9)	(6.8)
Noncash Acquisitions Under Capital Leases		43.5	44.5
Construction Expenditures Included in Current Liabilities as of September 30,		882.3	791.6
Construction Expenditures Included in Noncurrent Liabilities as of September 30,		0	71.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,		12.1	0.6
Noncash Contribution of Assets by Noncontrolling Interest		84	0
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage		2.1	2.8
AEP Texas Inc. [Member]
Operating Activities
Net Income (Loss)		151.1	146.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		364.9	343
Deferred Income Taxes		(21.2)	124.1
Allowance for Equity Funds Used During Construction		(15.2)	(2.2)
Mark-to-Market of Risk Management Contracts		0	0.1
Pension Contributions to Qualified Plan Trust		0	(8.8)
Property Taxes		(19.2)	(15.9)
Change in Regulatory Asset – Catastrophe Reserve		(22.3)	(72.3)
Change in Other Noncurrent Assets		(14.2)	(29.1)
Change in Other Noncurrent Liabilities		67.1	7.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(26.5)	(47.6)
Fuel, Materials and Supplies		(2.4)	(0.1)
Accounts Payable		(19.1)	77.3
Accrued Taxes, Net		40	1.7
Other Current Assets		(6.3)	(2.5)
Other Current Liabilities		14.1	(31.2)
Net Cash Flows from (Used for) Operating Activities		490.8	490.5
Investing Activities
Construction Expenditures		(1,096.1)	(617.5)
Change in Advances to Affiliates, Net		103.9	(437)
Other Investing Activities		31.1	11.5
Net Cash Flows from (Used for) Investing Activities		(961.1)	(1,043)
Financing Activities
Capital Contributions from Parent		100	200
Issuance of Long-term Debt		494	749.9
Change in Advances from Affiliates, Net		77.8	(169.5)
Retirement of Long-term Debt		(231.7)	(248.4)
Principal Payments for Capital Lease Obligations		(3.6)	(3)
Other Financing Activities		0.9	(0.3)
Net Cash Flows from (Used for) Financing Activities		437.4	528.7
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		(32.9)	(23.8)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		157.2	146.9
Cash and Cash Equivalents at Beginning of Period		2
Cash, Cash Equivalents and Restricted Cash at End of Period		124.3	123.1
Cash and Cash Equivalents at End of Period		0.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		92.2	101.1
Net Cash Paid (Received) for Income Taxes		(14.2)	(23.3)
Noncash Acquisitions Under Capital Leases		8.9	5.3
Construction Expenditures Included in Current Liabilities as of September 30,		176.4	166.1
AEP Transmission Co [Member]
Operating Activities
Net Income (Loss)	[1]	244.2	212.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		97.5	69.7
Deferred Income Taxes		76.3	191.9
Allowance for Equity Funds Used During Construction		(48.7)	(33)
Property Taxes		86.9	72.4
Long-term Accounts Receivable - Affiliated		(3.1)	(13.8)
Change in Other Noncurrent Assets		12.7	8.6
Change in Other Noncurrent Liabilities		18	25.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		23.5	(40.8)
Fuel, Materials and Supplies		(2.8)	(11)
Accounts Payable		3.3	20.4
Accrued Taxes, Net		(73.2)	(71.2)
Accrued Interest		20.9	18.4
Other Current Assets		(0.5)	(5.3)
Other Current Liabilities		(28)	0.5
Net Cash Flows from (Used for) Operating Activities		427	444.9
Investing Activities
Construction Expenditures		(1,171.8)	(1,050.7)
Change in Advances to Affiliates, Net		(131.7)	(223.8)
Acquisitions of Assets		(13.2)	(3.8)
Other Investing Activities		1.2	0.9
Net Cash Flows from (Used for) Investing Activities		(1,315.5)	(1,277.4)
Financing Activities
Capital Contributions from Parent		582	185.5
Issuance of Long-term Debt		321.1	618.3
Change in Advances from Affiliates, Net		(14.6)	28.7
Net Cash Flows from (Used for) Financing Activities		888.5	832.5
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		38.4	30.4
Net Cash Paid (Received) for Income Taxes		(32.1)	(93.4)
Construction Expenditures Included in Current Liabilities as of September 30,		237	248.9
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)		290	248.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		319.5	304.1
Deferred Income Taxes		(83.8)	121.7
Carrying Costs Income		(1.2)	(1)
Allowance for Equity Funds Used During Construction		(9.6)	(6.2)
Mark-to-Market of Risk Management Contracts		(43.7)	(28.3)
Pension Contributions to Qualified Plan Trust		0	(10.2)
Deferred Fuel Over/Under-Recovery, Net		12.8	4.9
Change in Other Noncurrent Assets		94.8	37.1
Change in Other Noncurrent Liabilities		3.8	7.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		39.4	39.9
Fuel, Materials and Supplies		53	14
Accounts Payable		(21.5)	6.2
Accrued Taxes, Net		(20.2)	(44.2)
Other Current Assets		(7.9)	(2.5)
Other Current Liabilities		64.1	9.1
Net Cash Flows from (Used for) Operating Activities		690.7	702.2
Investing Activities
Construction Expenditures		(575.8)	(560)
Change in Advances to Affiliates, Net		0.4	0.5
Other Investing Activities		10	11.8
Net Cash Flows from (Used for) Investing Activities		(565.4)	(547.7)
Financing Activities
Issuance of Long-term Debt		103.3	320.9
Change in Advances from Affiliates, Net		(87.5)	(10.1)
Retirement of Long-term Debt		(24)	(377.9)
Principal Payments for Capital Lease Obligations		(5.2)	(5.2)
Dividends Paid on Common Stock		(120)	(90)
Other Financing Activities		1	0.5
Net Cash Flows from (Used for) Financing Activities		(132.4)	(161.8)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		(7.1)	(7.3)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		19.2	18.5
Cash and Cash Equivalents at Beginning of Period		2.9
Cash, Cash Equivalents and Restricted Cash at End of Period		12.1	11.2
Cash and Cash Equivalents at End of Period		2.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		104.5	107.1
Net Cash Paid (Received) for Income Taxes		26.7	24.4
Noncash Acquisitions Under Capital Leases		3.9	2.9
Construction Expenditures Included in Current Liabilities as of September 30,		87.6	107.2
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)		231.6	143.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		207.1	154.8
Deferred Income Taxes		28.1	132.2
Deferral of Incremental Nuclear Refueling Outage Expenses, Net		13.5	15.5
Carrying Costs Income		(4.6)	(9.9)
Allowance for Equity Funds Used During Construction		(8)	(8.1)
Mark-to-Market of Risk Management Contracts		(0.3)	(7.5)
Amortization of Nuclear Fuel		82.6	104.8
Pension Contributions to Qualified Plan Trust		0	(13)
Deferred Fuel Over/Under-Recovery, Net		29.6	22
Change in Other Noncurrent Assets		(7.4)	(32.2)
Change in Other Noncurrent Liabilities		46.3	40.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		6.5	19.3
Fuel, Materials and Supplies		(1.1)	(4.1)
Accounts Payable		(34.7)	16.6
Customer Deposits		(0.7)	3
Accrued Taxes, Net		(7.1)	(30.2)
Accrued Interest		(15.3)	(17.4)
Other Current Assets		4.9	8
Other Current Liabilities		0.3	(14.2)
Net Cash Flows from (Used for) Operating Activities		571.3	524.3
Investing Activities
Construction Expenditures		(434.5)	(469.2)
Change in Advances to Affiliates, Net		(60.1)	(0.1)
Purchases of Investment Securities		(1,589)	(1,842.2)
Sales of Investment Securities		1,550.9	1,808.6
Acquisitions of Nuclear Fuel		(26.1)	(73.2)
Other Investing Activities		9.2	7.3
Net Cash Flows from (Used for) Investing Activities		(549.6)	(568.8)
Financing Activities
Issuance of Long-term Debt		1,168.1	411.1
Change in Advances from Affiliates, Net		(211.6)	(37.7)
Retirement of Long-term Debt		(856.1)	(227.1)
Principal Payments for Capital Lease Obligations		(7.3)	(8.7)
Dividends Paid on Common Stock		(105.5)	(93.7)
Other Financing Activities		(9)	0.7
Net Cash Flows from (Used for) Financing Activities		(21.4)	44.6
Net Increase (Decrease) in Cash and Cash Equivalents		0.3	0.1
Cash and Cash Equivalents at Beginning of Period		1.3	1.2
Cash and Cash Equivalents at End of Period		1.6	1.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		104.4	92
Net Cash Paid (Received) for Income Taxes		(26.5)	(69.6)
Noncash Acquisitions Under Capital Leases		4.4	5.9
Construction Expenditures Included in Current Liabilities as of September 30,		66.4	74.5
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,		12.1	0.6
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage		2.1	2.8
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)		237.1	231.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		200.3	165.7
Amortization Of Generation Deferrals		171.9	172.9
Deferred Income Taxes		(71.9)	117.5
Carrying Costs Income		(1.5)	(3)
Allowance for Equity Funds Used During Construction		(7.8)	(4.1)
Mark-to-Market of Risk Management Contracts		(37.1)	19.5
Pension Contributions to Qualified Plan Trust		0	(8.2)
Property Taxes		191.1	175.9
Provision for Refund - Global Settlement		(5.5)	(93.3)
Change in Regulatory Assets		180.9	(82.2)
Change in Other Noncurrent Assets		0.8	(44.5)
Change in Other Noncurrent Liabilities		62.5	43.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		21.3	14.9
Fuel, Materials and Supplies		(3.7)	(7.1)
Accounts Payable		(31.8)	(31.2)
Accrued Taxes, Net		(210.6)	(284.3)
Other Current Assets		9.1	(17.3)
Other Current Liabilities		(4.3)	(34.8)
Net Cash Flows from (Used for) Operating Activities		700.8	330.9
Investing Activities
Construction Expenditures		(538.5)	(362.5)
Change in Advances to Affiliates, Net		0	24.2
Other Investing Activities		15.5	6.9
Net Cash Flows from (Used for) Investing Activities		(523)	(331.4)
Financing Activities
Issuance of Long-term Debt		392.8	0
Change in Advances from Affiliates, Net		155.1	167.6
Retirement of Long-term Debt		(397)	(46.4)
Principal Payments for Capital Lease Obligations		(2.9)	(3.1)
Dividends Paid on Common Stock		(337.5)	(130)
Other Financing Activities		0.7	0.8
Net Cash Flows from (Used for) Financing Activities		(188.8)	(11.1)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		(11)	(11.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		29.7	30.3
Cash and Cash Equivalents at Beginning of Period		3.1
Cash, Cash Equivalents and Restricted Cash at End of Period		18.7	18.7
Cash and Cash Equivalents at End of Period		3.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		67.3	68.1
Net Cash Paid (Received) for Income Taxes		54.1	69.6
Noncash Acquisitions Under Capital Leases		3	3.6
Construction Expenditures Included in Current Liabilities as of September 30,		66	56.8
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)		89.8	71.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		120.5	97.8
Deferred Income Taxes		(13.4)	93.7
Allowance for Equity Funds Used During Construction		0.3	(0.4)
Mark-to-Market of Risk Management Contracts		(11.5)	(3.9)
Pension Contributions to Qualified Plan Trust		0	(5.3)
Property Taxes		(9.6)	(9.4)
Deferred Fuel Over/Under-Recovery, Net		73.3	(5.6)
Provision for Refund		3.7	(39.4)
Change in Other Noncurrent Assets		6.9	(19.8)
Change in Other Noncurrent Liabilities		10.9	(1.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(3.4)	5.8
Fuel, Materials and Supplies		(1.5)	13.5
Accounts Payable		6.9	(18.5)
Accrued Taxes, Net		38.4	20.1
Other Current Assets		0.3	(8.2)
Other Current Liabilities		15.1	1.5
Net Cash Flows from (Used for) Operating Activities		326.7	191.9
Investing Activities
Construction Expenditures		(162.8)	(203.1)
Other Investing Activities		3.9	1.5
Net Cash Flows from (Used for) Investing Activities		(158.9)	(201.6)
Financing Activities
Change in Advances from Affiliates, Net		(127.6)	66
Retirement of Long-term Debt		(0.3)	(0.3)
Principal Payments for Capital Lease Obligations		(2.5)	(3.2)
Dividends Paid on Common Stock		(37.5)	(52.5)
Other Financing Activities		0.4	0.3
Net Cash Flows from (Used for) Financing Activities		(167.5)	10.3
Net Increase (Decrease) in Cash and Cash Equivalents		0.3	0.6
Cash and Cash Equivalents at Beginning of Period		1.6	1.5
Cash and Cash Equivalents at End of Period		1.9	2.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		42	40.9
Net Cash Paid (Received) for Income Taxes		1.6	(46.6)
Noncash Acquisitions Under Capital Leases		2.3	1
Construction Expenditures Included in Current Liabilities as of September 30,		24.3	15.1
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)		141.7	126.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		175.9	158.1
Deferred Income Taxes		2	79.8
Allowance for Equity Funds Used During Construction		(3.8)	(1.2)
Mark-to-Market of Risk Management Contracts		2.5	(12.5)
Pension Contributions to Qualified Plan Trust		0	(8.9)
Property Taxes		(15.8)	(15.4)
Deferred Fuel Over/Under-Recovery, Net		4.4	2.4
Change in Other Noncurrent Assets		(8.9)	(2.9)
Change in Other Noncurrent Liabilities		52.1	(5.2)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		44.3	12.1
Fuel, Materials and Supplies		5	13.6
Accounts Payable		(29.9)	(25.7)
Accrued Taxes, Net		38.4	69.1
Accrued Interest		(11.4)	(20)
Other Current Assets		3.2	0.7
Other Current Liabilities		15.6	(14.6)
Net Cash Flows from (Used for) Operating Activities		415.3	355.9
Investing Activities
Construction Expenditures		(336.6)	(265.3)
Change in Advances to Affiliates, Net		(516.6)	167.8
Other Investing Activities		1.2	3.1
Net Cash Flows from (Used for) Investing Activities		(852)	(94.4)
Financing Activities
Issuance of Long-term Debt		1,015.4	114.6
Change in Short-term Debt, Net		(2.6)	14.3
Change in Advances from Affiliates, Net		(118.7)	48.3
Retirement of Long-term Debt		(385.3)	(353.6)
Principal Payments for Capital Lease Obligations		(8.5)	(8.4)
Dividends Paid on Common Stock		(60)	(82.5)
Dividends Paid on Common Stock		(3.2)	(2.7)
Other Financing Activities		0.5	0.4
Net Cash Flows from (Used for) Financing Activities		437.6	(269.6)
Net Increase (Decrease) in Cash and Cash Equivalents		0.9	(8.1)
Cash and Cash Equivalents at Beginning of Period		1.6	10.3
Cash and Cash Equivalents at End of Period		2.5	2.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts		102.5	109.4
Net Cash Paid (Received) for Income Taxes		12.9	(70.5)
Noncash Acquisitions Under Capital Leases		3.2	2.8
Construction Expenditures Included in Current Liabilities as of September 30,		$ 37	$ 40.7
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.

Significant Accounting Matters

Significant Accounting Matters	9 Months Ended
	Sep. 30, 2018
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2018 is not necessarily indicative of results that may be expected for the year ending December 31, 2018 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2017 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 22, 2018 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2018 2017 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 577.6 $ 544.7 Weighted Average Number of Basic Shares Outstanding 493.0 $ 1.17 491.8 $ 1.11 Weighted Average Dilutive Effect of Stock-Based Awards 0.9 — 1.2 (0.01 ) Weighted Average Number of Diluted Shares Outstanding 493.9 $ 1.17 493.0 $ 1.10 Nine Months Ended September 30, 2018 2017 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,560.4 $ 1,511.9 Weighted Average Number of Basic Shares Outstanding 492.6 $ 3.17 491.8 $ 3.07 Weighted Average Dilutive Effect of Stock-Based Awards 0.9 (0.01 ) 0.6 — Weighted Average Number of Diluted Shares Outstanding 493.5 $ 3.16 492.4 $ 3.07 There were no antidilutive shares outstanding as of September 30, 2018 and 2017 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Revisions to Previously Issued Financial Statements (Applies to only AEPTCo) In the second quarter of 2018, management identified certain transmission assets that it believes should not have been included in AEPTCo’s SPP transmission formula rates. As a result, AEPTCo recorded a pretax out of period correction of an error of approximately $17 million related to revenue recorded from 2013 through March 31, 2018 in the second quarter of 2018 . Subsequent to filing the second quarter 2018 Form 10-Q, AEPTCo identified an additional error in its previously issued financial statements. This error resulted from the improper capitalization of AFUDC and subsequent revenue recorded on the AFUDC. The impact of this misstatement reduced AEPTCo’s pretax income by approximately $7 million on a cumulative basis for the period 2011 through June 30, 2018 . Management assessed the materiality of the misstatements on all previously issued AEPTCo financial statements in accordance with SEC Staff Accounting Bulletin (SAB) No. 99, Materiality, codified in ASC 250, Presentation of Financial Statements and concluded these misstatements were not material, individually or in the aggregate, to any prior annual or interim period. In accordance with ASC 250 (SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements), management revised the prior period AEPTCo financial statements included in this report to reflect the impact of correcting the immaterial misstatements described above. In addition, management will revise the historical 2017, March 31, 2018 and June 30, 2018 periods presented in AEPTCo’s previously issued financial statements in future SEC Form 10-Q and Form 10-K filings to reflect the impact of the misstatements. The $(18) million adjustment to pretax income for the nine months ended September 30, 2017 includes adjustments of $(12) million relating to 2016 and earlier periods. The effect of recording this adjustment of $(12) million in 2017 is not material to AEPTCo’s financial statements for 2017 or any earlier period. AEPTCo has also corrected other previously recorded immaterial out of period adjustments. The impact of these additional adjustments did not impact net income in any period. Management also assessed the materiality of the AEPTCo’s misstatements discussed above on all previously issued and the current year AEP financial statements in accordance with ASC 250, and concluded these misstatements were not material, individually or in the aggregate, to any prior and current interim and annual period financial statements. As a result, AEP recorded the correction in the third quarter of 2018. Statements of Income The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statements of income for the three and nine months ended September 30, 2017: Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 As Reported Adjustments As Adjusted As Reported Adjustments As Adjusted (in millions) (in millions) TOTAL REVENUES $ 167.3 $ (1.7 ) $ 165.6 $ 549.4 $ (14.6 ) $ 534.8 EXPENSES Depreciation and Amortization 24.8 (0.2 ) 24.6 70.9 (1.2 ) 69.7 TOTAL EXPENSES 72.2 (0.2 ) 72.0 198.5 (1.2 ) 197.3 OPERATING INCOME 95.1 (1.5 ) 93.6 350.9 (13.4 ) 337.5 Other Income (Expense): Allowance for Equity Funds Used During Construction 11.7 (0.3 ) 11.4 36.0 (3.0 ) 33.0 Interest Expense (16.9 ) (0.2 ) (17.1 ) (48.6 ) (1.8 ) (50.4 ) INCOME BEFORE INCOME TAX EXPENSE 90.1 (2.0 ) 88.1 338.8 (18.2 ) 320.6 Income Tax Expense 30.2 (0.7 ) 29.5 114.5 (6.3 ) 108.2 NET INCOME $ 59.9 $ (1.3 ) $ 58.6 $ 224.3 $ (11.9 ) $ 212.4 Balance Sheet The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s Balance Sheet as of December 31, 2017: December 31, 2017 As Reported Adjustment As Adjusted CURRENT ASSETS (in millions) Accounts Receivable: Customers $ 19.1 $ (4.1 ) $ 15.0 Total Accounts Receivable 113.6 (4.1 ) 109.5 Accrued Tax Benefits 46.6 2.8 49.4 TOTAL CURRENT ASSETS 327.7 (1.3 ) 326.4 TRANSMISSION PROPERTY Transmission Property 5,336.1 (16.4 ) 5,319.7 Other Property, Plant and Equipment 131.4 (4.6 ) 126.8 Construction Work in Progress 1,312.7 11.3 1,324.0 Total Transmission Property 6,780.2 (9.7 ) 6,770.5 Accumulated Depreciation and Amortization 170.4 (17.8 ) 152.6 TOTAL TRANSMISSION PROPERTY – NET 6,609.8 8.1 6,617.9 OTHER NONCURRENT ASSETS Deferred Property Taxes 117.8 7.2 125.0 TOTAL OTHER NONCURRENT ASSETS 130.6 7.2 137.8 TOTAL ASSETS $ 7,068.1 $ 14.0 $ 7,082.1 CURRENT LIABILITIES Accounts Payable: General $ 473.2 $ 11.3 $ 484.5 Affiliated Companies 52.9 13.2 66.1 Accrued Taxes 225.4 6.1 231.5 TOTAL CURRENT LIABILITIES 836.3 30.6 866.9 NONCURRENT LIABILITIES Deferred Income Taxes 601.7 (1.3 ) 600.4 Regulatory Liabilities 493.7 0.1 493.8 TOTAL NONCURRENT LIABILITIES 3,626.5 (1.2 ) 3,625.3 TOTAL LIABILITIES 4,462.8 29.4 4,492.2 MEMBER’S EQUITY Retained Earnings 788.7 (15.4 ) 773.3 TOTAL MEMBER’S EQUITY 2,605.3 (15.4 ) 2,589.9 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 7,068.1 $ 14.0 $ 7,082.1 Statement of Cash Flows The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statement of cash flows for the nine months ended September 30, 2017: Nine Months Ended September 30, 2017 As Reported Adjustments As Adjusted (in millions) OPERATING ACTIVITIES Net Income $ 224.3 $ (11.9 ) $ 212.4 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 70.9 (1.2 ) 69.7 Deferred Income Taxes 193.0 (1.1 ) 191.9 Allowance for Equity Funds Used During Construction (36.0 ) 3.0 (33.0 ) Change in Other Noncurrent Assets 7.6 1.0 8.6 Changes in Certain Components of Working Capital: Accounts Receivable, Net (44.4 ) 3.6 (40.8 ) Accounts Payable 8.6 11.8 20.4 Accrued Taxes, Net (66.0 ) (5.2 ) (71.2 ) Net Cash Flows from Operating Activities 444.9 — 444.9 INVESTING ACTIVITIES Net Cash Flows Used for Investing Activities (1,277.4 ) — (1,277.4 ) FINANCING ACTIVITIES Net Cash Flows from Financing Activities 832.5 — 832.5 Net Change in Cash and Cash Equivalents — — — Cash and Cash Equivalents at Beginning of Period — — — Cash and Cash Equivalents at End of Period $ — $ — $ — SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 28.6 $ 1.8 $ 30.4 Construction Expenditures Included in Current Liabilities as of September 30, 239.0 9.9 248.9 Statement of Changes in Member’s Equity The statement of changes in AEPTCo’s member’s equity reflects the adjustments to Net Income of $(1) million and $(12) million for the three and nine months ended September 30, 2017 as shown in the table under Net Income above. The statement of changes in member’s equity also reflects the adjustments to Retained Earnings of $(15) million as of December 31, 2017 as shown in the table under Balance Sheet above. Restricted Cash (Applies to AEP, AEP Texas, APCo and OPCo) Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds. Reconciliation of Cash, Cash Equivalents and Restricted Cash The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported on the balance sheets that sum to the total of the same amounts shown on the statements of cash flows: September 30, 2018 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 788.3 $ 0.1 $ 2.2 $ 3.5 Restricted Cash 149.2 124.2 9.9 15.2 Total Cash, Cash Equivalents and Restricted Cash $ 937.5 $ 124.3 $ 12.1 $ 18.7 December 31, 2017 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 214.6 $ 2.0 $ 2.9 $ 3.1 Restricted Cash 198.0 155.2 16.3 26.6 Total Cash, Cash Equivalents and Restricted Cash $ 412.6 $ 157.2 $ 19.2 $ 29.7

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. During FASB’s standard-setting process and upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 changing the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. Management adopted ASU 2014-09 effective January 1, 2018, by means of the modified retrospective approach for all contracts. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. In that regard, the application of the new standard did not cause any significant differences in any individual financial statement line items had those line items been presented in accordance with the guidance that was in effect prior to the adoption of the new standard. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in the Registrants’ previously established accounting policies for revenue. See Note 14 - Revenue from Contracts with Customers for additional disclosures required by the new standard. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 revising the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018, with early adoption permitted. In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements”, which provides an optional expedient to adopt the new lease requirements through a cumulative-effect adjustment in the period of adoption. Management plans to apply the new optional transition guidance. New leasing standard implementation activities to date include 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. A lease system was selected after reviewing multiple system options. System implementation activities of core functionality continue in the fourth quarter of 2018. Implementation of reporting functionality designed to meet new disclosure requirements is ongoing. Management plans to elect certain of the optional 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. Evaluation of new lease contracts will continue through the fourth quarter. Management expects the new standard to impact financial position and, at this time, cannot estimate the impact. Management does not expect any impact to results of operations or cash flows. Management plans to adopt ASU 2016-02 and its related guidance effective January 1, 2019. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. Management adopted ASU 2017-07 effective January 1, 2018. Presentation of the non-service components on a separate line outside of operating income was applied on a retrospective basis, using the amounts disclosed in the benefit plan note for the estimation basis as a practical expedient. Capitalization of only the service cost component was applied on a prospective basis. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Among other things, ASU 2017-12: (a) expands the types of transactions eligible for hedge accounting, (b) eliminates the separate measurement and presentation of hedge ineffectiveness, (c) simplifies the requirements around the assessment of hedge effectiveness, (d) provides companies more time to finalize hedge documentation and (e) enhances presentation and disclosure requirements. Management early adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018, by means of a modified retrospective approach. The adoption of ASU 2017-12 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in the Registrants’ previously established accounting policies for derivatives and hedging. ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02) In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. The accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be adjusted for the effect of a change in tax law or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date of the tax change. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI would not reflect the newly enacted corporate tax rate. Management adopted ASU 2018-02 effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. A portion of the reclassification was recorded to Regulatory Liabilities to adjust the tax effects of certain interest rate hedges in AEP's regulated jurisdictions that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement of financial position and did not impact results of operations or cash flows. ASU 2018-15 “Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” (ASU 2018-15) In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. Capitalized implementation costs of a hosting arrangement that is a service contract should be amortized over the term of the hosting arrangement. The expense related to the capitalized implementation costs should be presented in the same line item in the statement of income as the fees associated with the hosting element (service) of the arrangement. Payments for capitalized implementation costs in the statement of cash flows should be classified in the same manner as payments made for fees associated with the hosting element. Capitalized implementation costs in the statement of financial position should be presented in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The amendments may be applied either retrospectively or prospectively to applicable implementation costs incurred after the date of adoption. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2018-15 prospectively, effective January 1, 2020.

Comprehensive Income

Comprehensive Income	9 Months Ended
	Sep. 30, 2018
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2018 and 2017 . 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 Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedges Commodity Interest Rate Pension 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) Credit (5.9 ) 0.4 (1.8 ) (7.3 ) Income Tax (Expense) Credit (1.3 ) 0.1 (0.4 ) (1.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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 Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.9 ) — — — (0.9 ) Purchased Electricity for Resale (a) 4.9 — — — 4.9 Interest Expense (a) — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension 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) Credit (23.7 ) 0.9 — (5.1 ) (27.9 ) Income Tax (Expense) Credit (5.0 ) 0.2 — (1.1 ) (5.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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 (b) (6.1 ) (2.7 ) — (8.2 ) (17.0 ) ASU 2016-01 Adoption (b) — — (11.9 ) — (11.9 ) Balance in AOCI as of September 30, 2018 $ (22.8 ) $ (12.7 ) $ — $ (50.5 ) $ (86.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (5.6 ) — — — (5.6 ) Purchased Electricity for Resale (a) 26.0 — — — 26.0 Interest Expense (a) — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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 Amortization of Prior Service Cost (Credit) — — — Amortization of Actuarial (Gains)/Losses — — — Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (4.9 ) $ (9.4 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.3 — 0.3 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) Credit 0.3 0.1 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 0.1 0.3 Net Current Period Other Comprehensive Income (Loss) 0.2 0.1 0.3 Balance in AOCI as of September 30, 2017 $ (4.7 ) $ (9.3 ) $ (14.0 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 1.0 0.1 1.1 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 0.1 0.9 Net Current Period Other Comprehensive Income (Loss) 0.8 0.1 0.9 ASU 2018-02 Adoption (b) (0.9 ) (1.8 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (4.6 ) $ (9.8 ) $ (14.4 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (5.4 ) $ (9.5 ) $ (14.9 ) 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 — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 0.3 1.3 Income Tax (Expense) Credit 0.3 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 0.2 0.9 Net Current Period Other Comprehensive Income (Loss) 0.7 0.2 0.9 Balance in AOCI as of September 30, 2017 $ (4.7 ) $ (9.3 ) $ (14.0 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit (0.4 ) (0.9 ) (1.3 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedges Commodity Interest Rate Pension 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) Credit 0.9 (0.9 ) (2.9 ) (2.9 ) Income Tax (Expense) Credit 0.2 (0.2 ) (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 (b) — 0.5 (0.2 ) 0.3 Balance in AOCI as of September 30, 2018 $ — $ 2.0 $ (3.4 ) $ (1.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Income (Loss) (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.2 — 1.2 ASU 2018-02 Adoption (b) (2.4 ) (0.3 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (11.9 ) $ (1.7 ) $ (13.6 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income (Loss) 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – 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) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.4 ) Balance in AOCI as of September 30, 2018 $ 1.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 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) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 1.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Income (Loss) (1.0 ) ASU 2018-02 Adoption (b) 0.4 Balance in AOCI as of September 30, 2018 $ 1.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – 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) Credit (0.2 ) Income Tax (Expense) Credit — Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2018 $ 2.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 2.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.7 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) ASU 2018-02 Adoption (b) 0.5 Balance in AOCI as of September 30, 2018 $ 2.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Income (Loss) (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 0.5 (0.4 ) 0.1 Income Tax (Expense) Credit 0.1 (0.1 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 1.6 (1.3 ) 0.3 Income Tax (Expense) Credit 0.3 (0.3 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (1.0 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 3.6 (1.0 ) 2.6 ASU 2018-02 Adoption (b) (1.3 ) 0.4 (0.9 ) Balance in AOCI as of September 30, 2018 $ (3.7 ) $ 1.4 $ (2.3 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) (a) Amounts reclassified to the referenced line item on the statements of income. (b) See Note 2 - New Accounting Pronouncements for additional information.

Rate Matters

Rate Matters	9 Months Ended
	Sep. 30, 2018
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2017 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2017 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 2018 and updates the 2017 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, for the generating unit as of September 30, 2018 . See “2018 Oklahoma Base Rate Case” below for additional information. Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (dollars in millions) $ 106.5 $ 56.8 $ 49.7 $ 3.1 $ 5.0 2020 28 years Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo and OPCo) AEP September 30, December 31, 2018 2017 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 20.1 9.6 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 151.7 128.0 Plant Retirement Costs - Asset Retirement Obligation Costs 39.7 39.7 Cook Plant Uprate Project — 36.3 Cook Plant Turbine — 15.9 Other Regulatory Assets Pending Final Regulatory Approval 18.8 42.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 280.6 $ 322.0 (a) As of September 30, 2018 , AEP Texas has deferred $127 million related to Hurricane Harvey and is in the process of requesting securitization of the distribution portion of the regulatory asset. (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff. AEP Texas September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) $ 150.2 $ 123.3 Rate Case Expense 0.2 0.1 Total Regulatory Assets Pending Final Regulatory Approval $ 150.4 $ 123.4 (a) As of September 30, 2018 , AEP Texas has deferred $127 million related to Hurricane Harvey and is in the process of requesting securitization of the distribution portion of the regulatory asset. APCo September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.0 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 39.7 39.7 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 49.3 $ 49.4 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff. I&M September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ — $ 36.3 Deferred Cook Plant Life Cycle Management Project Costs - Michigan — 14.7 Cook Plant Turbine — 15.9 Rockport Dry Sorbent Injection System - Indiana — 10.4 Other Regulatory Assets Pending Final Regulatory Approval 3.4 2.0 Total Regulatory Assets Pending Final Regulatory Approval $ 3.4 $ 79.3 PSO September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Storm-Related Costs $ — $ 3.2 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.1 Total Regulatory Assets Pending Final Regulatory Approval $ 0.5 $ 3.3 SWEPCo September 30, December 31, 2018 2017 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 0.5 0.5 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation - Arkansas, Louisiana 5.0 4.0 Rate Case Expense - Texas 4.6 4.3 Shipe Road Transmission Project - FERC — 3.3 Other Regulatory Assets Pending Final Regulatory Approval 3.3 2.5 Total Regulatory Assets Pending Final Regulatory Approval $ 63.7 $ 64.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. Impact of Tax Reform Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which impacts outstanding rate and regulatory matters. For additional details on the impact of Tax Reform, see Note 11 - Income Taxes. AEP Texas Rate Matters (Applies to AEP and AEP Texas) AEP Texas Interim Transmission and Distribution Rates As of September 30, 2018 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2018, subject to review, are estimated to be $959 million . A base rate review could produce a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019. In 2018, the PUCT issued approvals to increase AEP Texas’ transmission rates by $22 million annually. The approvals included an increase in annual revenues to recover transmission capital additions of $46 million offset by a reduction in annual revenues of $24 million due to the reduction in the federal income tax rate due to Tax Reform. The approvals did not address the return of Excess ADIT benefits to customers. In August 2018, the PUCT approved a Stipulation and Settlement agreement to amend AEP Texas’ Distribution Cost Recovery Factor to reduce annual distribution rates by approximately $24 million annually, beginning September 1, 2018. The settlement included an increase in annual revenues to recover 2017 distribution capital additions of $19 million offset by reductions in annual revenues of: (a) $21 million due to the reduction in the federal income tax rate due to Tax Reform, (b) $10 million due to Excess ADIT associated with certain depreciable property to be amortized using ARAM and (c) $12 million due to Excess ADIT that is not subject to rate normalization requirements to be refunded over 5 years. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2018 , the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $150 million , inclusive of approximately $127 million of incremental storm expenses related to Hurricane Harvey. As of September 30, 2018 , AEP Texas has recorded approximately $205 million of capital expenditures related to Hurricane Harvey. Also, as of September 30, 2018 , AEP Texas has received $10 million in insurance proceeds, and has recorded a receivable for an additional $4 million that will be received in the fourth quarter of 2018, which were applied to the Hurricane Harvey related regulatory asset and property, plant and equipment balances. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and is in the process of requesting securitization of the distribution portion of the regulatory asset. The standard process for securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018, AEP Texas filed a Determination of System Restoration Costs with the PUCT for total estimated storm costs in the amount of $425 million , which includes estimated carrying costs. The estimated value of the total storm costs net of insurance proceeds, tax credits and Excess ADIT is $370 million . AEP Texas intends to request securitization for distribution related assets of $253 million while the remaining $117 million of transmission related assets will be recovered through interim transmission filings or an upcoming base rate case. The request for securitization is expected to occur by the first quarter of 2019. In October 2018, intervenors filed testimony requesting a $24 million reduction in AEP Texas’ Determination of System Restoration Costs. Also in October 2018, the PUCT staff filed testimony requesting a $4 million reduction AEP Texas’ Determination of System Restoration Costs. Settlement negotiations are ongoing. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it could have an adverse effect on future net income, cash flows and financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Earnings Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates were frozen until after the Virginia SCC ruled on APCo’s next biennial review. These amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that: (a) on a one-time basis, required APCo to exclude $10 million of incurred fuel expenses from the July 2018 over/under recovery calculation, (b) reduced APCo’s base rates by $50 million annually effective July 30, 2018, on an interim basis and subject to true-up, to reflect the reduction in the federal income tax rate due to Tax Reform, (c) will require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) will require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) will require APCo to seek approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period ending July 1, 2028 and (f) will require APCo to construct and/or acquire solar generation facilities in Virginia, as approved by the Virginia SCC, of at least 200 MW of aggregate capacity by July 1, 2028. Triennial reviews are subject to an earnings test which provides that 70% of any over earnings would be refunded or may be reinvested in approved energy distribution grid transformation projects and/or new utility-owned solar and wind generation facilities. The Virginia SCC’s triennial review of 2017-2019 APCo earnings could reduce future net income and cash flows and impact financial condition. Virginia Tax Reform In October 2018, the Virginia SCC issued an order approving APCo’s request to refund $55 million of Excess ADIT that is not subject to rate normalization requirements to customers through a rider. The rider will be paid over twelve months effective November 1, 2018 and will offset APCo’s recent increase in interim fuel rates, subject to refund, that was filed with the Virginia SCC. In October 2018, APCo submitted a filing with the Virginia SCC to resolve outstanding issues related to Tax Reform. The filing incorporated amounts already refunded to customers as disclosed in “Virginia Legislation Affecting Earnings Reviews” above and, if approved, will reduce APCo’s base rates by an additional $7 million annually. The combined reduction in APCo’s base rates due to Tax Reform will refund: (a) $39 million annually of excess federal income taxes collected since January 1, 2018 until new base rates are implemented, (b) $7 million annually of Excess ADIT associated with certain depreciable property using ARAM and (c) $11 million annually of Excess ADIT that is not subject to rate normalization requirements over 10 years. APCo anticipates a final order from the Virginia SCC in the first quarter of 2019 and expects to implement additional customer rate credits in a tax-related rider starting in April 2019. The Virginia SCC’s review of APCo’s October 2018 Tax Reform filing could reduce future net income and cash flows and impact financial condition. 2018 West Virginia Base Rate Case In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ( $98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase includes $32 million ( $28 million related to APCo) due to increased annual depreciation rates and also reflects 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 discussed below. In October 2018, WVPSC staff and intervenors filed testimony. WVPSC staff recommended a $2 million annual net revenue increase based on a 9.25% return on common equity while intervenors recommended a $14 million annual net revenue decrease based on an 8.75% return on common equity. The difference between APCo and WPCo’s requested annual base rate increase and the WVPSC staff and intervenors recommendations are primarily due to: (a) a reduction in the requested return on common equity, (b) the rejection of updates to the rate base calculation methodology, (c) the rejection of updates to rate base for certain known plant in service increases in 2018 and (d) a reduction in annual depreciation rates primarily related to continuing with a 2040 retirement date for Clinch River Plant rather than APCo’s proposed retirement date of 2025. A hearing at the WVPSC is scheduled for November 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. West Virginia Tax Reform In August 2018, the WVPSC approved a settlement agreement between APCo, WPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform. The agreement will provide refunds to customers, through a rider, of approximately $63 million ( $51 million related to APCo) through June 2020. In addition, APCo and WPCo utilized $139 million ( $125 million related to APCo) of current tax savings and Excess ADIT to offset regulatory asset balances related to carbon capture, storm damage, ENEC and vegetation management. The remaining balance of $87 million ( $77 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements will be addressed by the WVPSC at a later date. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through September 30, 2018 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $849 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021. In June 2018, the PUCT approved ETT’s application to reduce its transmission rates by $28 million annually, beginning June 21, 2018, to reflect the reduction in the federal income tax rate due to Tax Reform. The filing did not address the return of Excess ADIT benefits to customers. In September 2018, ETT filed a request with the PUCT to refund $11 million of excess federal income taxes collected in 2018 prior to the reduction in transmission rates that were implemented on June 21, 2018. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. In February 2018, I&M filed a Stipulation and Settlement Agreement for a $97 million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures. The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily a result of: (a) the reduction in the federal income tax rate due to Tax Reform, (b) the feedback of credits for Excess ADIT, (c) a 9.95% return on equity, (d) longer recovery periods of regulatory assets, (e) lower depreciation expense primarily for meters, (f) an increase in the sharing of off-system sales margins with customers from 50% to 95% and (g) a refund of $4 million from July 2018 through December 2018 for the impact of Tax Reform for the period January 2018 through June 2018. In May 2018, the IURC issued an order approving the Stipulation and Settlement Agreement in its entirety. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase included $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million , including an intervenor’s proposal for up to 10% of I&M’s Michigan retail customers to choose an alternate supplier for generation and a proposed capacity rate based on PJM’s net cost of new entry value of $289 /MW-day, as well as the MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8% . If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million . In October 2018, I&M filed a request with the MPSC seeking authority to defer costs related to customers choosing an alternate supplier starting in February 2019. In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $50 million , effective April 2018 based on a 9.9% return on common equity. The MPSC also approved the ALJ’s recommendation related to the capacity rate. In May 2018, I&M filed a Petition for Rehearing on the capacity rate issue. In June 2018, the MPSC denied I&M’s request. Michigan Tax Reform In August 2018, the MPSC approved I&M’s application to refund, through a rider, approximately $9 million annually for the impact of Tax Reform on I&M’s Michigan jurisdictional earnings effective September 1, 2018. In October 2018, I&M also made two filings with the MPSC recommending to: (a) refund $3 million over eight months for the impact of Tax Reform on Michigan jurisdictional earnings for the period April 26, 2018 through August 31, 2018, (b) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (c) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over 10 years. An order from the MPSC is expected by the end of the first quarter of 2019. Rockport Plant, Unit 2 SCR In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements and is expected to be placed in service in May 2020. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. In March 2018, the IURC issued an order approving: (a) the CPCN, (b) the $274 million estimated cost of the SCR, excluding AFUDC, (c) deferral of the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recovery of these costs using an I&M Indiana rider. In April 2018, a group of intervenors filed a Petition for Reconsideration and Rehearing of the March 2018 IURC order. In June 2018, the IURC denied the Petition for Reconsideration and Rehearing. Management intends to request recovery of the Michigan jurisdictional share of the SCR project in a future base rate case. The AEGCo ownership share of the SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In January 2018, the KPSC issued an order approving a non-unanimous settlement agreement with certain modifications resulting in an annual revenue increase of $12 million , effective January 2018, based on a 9.7% return on equity. The KPSC’s primary revenue requirement modification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of a total of $50 million of Rockport Plant UPA expenses for the years 2018 through 2022, with the manner and timing of recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate case for three years with rates effective no earlier than 2021 and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life. In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million of annual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associated with forced outages and (c) capital structure adjustments. Also in February 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate be reflected in lower purchased power expense related to the Rockport UPA. In April 2018, KPCo and the intervenor filed a settlement agreement with the KPSC in which KPCo withdrew its requested increase related to the recovery of purchased power costs associated with forced outages and the intervenor withdrew its claim regarding the impact of the reduced corporate federal income tax rates on purchased power costs related to the Rockport UPA. In June 2018, the KPSC issued an order approving the settlement agreement including KPCo’s requested additional revenue increase of $765 thousand related to the calculation of federal income tax expense. This rate increase was effective June 28, 2018. Kentucky Tax Reform In June 2018, the KPSC issued an order approving a settlement agreement between KPCo and an intervenor that stipulates that KPCo will refund an estimated $82 million of Excess ADIT associated with certain depreciable property using ARAM and an estimated $93 million of Excess ADIT that is not subject to rate normalization requirements over 18 years. The refund was effective July 1, 2018. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015 and 2016, the PUCO issued orders in this proceeding. As part of the issued orders, the PUCO approved: (a) the DIR with modified revenue caps, (b) recovery of OVEC-related net margin incurred beginning June 2016, (c) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In April 2017, the PUCO rejected all pending rehearing requests related to the OVEC PPA. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In June 2018, oral arguments were held before the Supreme Court of Ohio. In November 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 August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In May 2018, OPCo and various intervenors filed requests for rehearing with the PUCO. In June 2018, these requests for rehearing were approved to allow further consideration of the requests. In August 2018, the PUCO denied all requests for rehearing. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. In January 2018, PUCO staff filed testimony that OPCo did not have signifi

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2017 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 $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2018 , no letters of credit were issued under the $3 billion revolving credit facility. In October 2018, the revolving credit facility was increased to $4 billion and extended until June 2022. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $305 million . The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2018 were as follows: Company Amount Maturity (in millions) AEP $ 71.8 October 2018 to September 2019 AEP Texas 2.8 January 2019 OPCo 0.6 September 2019 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $140 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $79 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2018 , SWEPCo has collected $74 million through a rider for final mine closure and reclamation costs, of which $79 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) 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, 2018 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2018 , there were no material liabilities recorded for any indemnifications. AEPSC conducts power purchase and sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase and sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf. Master Lease Agreements (Applies to all Registrants except AEPTCo) The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2018 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 47.7 AEP Texas 11.4 APCo 8.8 I&M 3.5 OPCo 7.6 PSO 4.1 SWEPCo 4.2 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo have exercised all renewal options for the maximum lease term. The future minimum lease obligations were $7 million and $7 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2018 . Under the remaining five-year lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which is equal to 77% of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee were $5 million and $5 million for I&M and SWEPCo, respectively, as of September 30, 2018 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2018 , the maximum potential amount of future payments required under the guaranteed leases was $46 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, 2018 , AEP’s boat and barge lease guarantee liability was $6 million , of which $1 million was recorded in Other Current Liabilities and $5 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. In January 2018, S&P Global Inc. downgraded the ratings of the nonaffiliated party and set their outlook to negative. In April 2018, Moody’s Investors Service Inc. also downgraded their ratings and set their outlook to negative. It is reasonably possible that enforcement of AEP’s liability for future payments under these leases could be exercised, which could reduce future net income and cash flows and impact financial condition. ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo) The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. 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 two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. As part of the reorganization, the bankruptcy court approved Westinghouse’s sale of its nuclear business to Brookfield WEC Holdings (Brookfield), a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts with Westinghouse. In August 2018, the sale closed. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. AEGCo and I&M sought and were granted dismissal of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. The court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. Plaintiffs voluntarily dismissed the surviving claims 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 on whether the trial court erred in dismissing plaintiffs’ claims for breach of contract and breach of the implied covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions in part. In June 2017, on rehearing, the court of appeals issued an amended opinion reversing the district court’s dismissal of certain of plaintiffs’ claims for breach of contract, vacating the denial of the plaintiffs’ motion for partial summary judgment and remanding the case to the district court for further proceedings. The amended opinion and judgment affirmed the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removed the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Responsive and supplemental filings have been made by all parties. In November 2017, the district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. In September 2018, the district court granted AEP’s unopposed motion to stay further proceedings regarding the consent decree to facilitate settlement discussions among the parties to the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint became the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members pursued personal injury/illness claims (non-working direct claims) and the remainder pursued loss of consortium claims. The plaintiffs sought compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. A settlement was reached with all of the plaintiffs and was approved by the WVMLP in June 2018. The settlement did not have a material impact on net income, cash flows or financial condition.

Dispostions and Impairments

Dispostions and Impairments	9 Months Ended
	Sep. 30, 2018
Impairment, Disposition and Assets and Liabilities Held for Sale	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to AEP only unless indicated otherwise. DISPOSITIONS Zimmer Plant (Generation & Marketing Segment) In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to a nonaffiliated party. The transaction closed in the second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition. The Income before Income Tax Expense and Equity Earnings of Zimmer Plant was immaterial for the three and nine months ended September 30, 2017. Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion , which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $226 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income. 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 statement 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. In December 2017, and in accordance with the accounting guidance for impairments of long-lived assets, an impairment analysis was triggered by the expected costs of the dam reconstruction activities, resulting in the conclusion that the fair value of Racine, in its present condition, was $0 as of December 31, 2017. A pretax impairment charge equal to Racine’s net book value of $43 million was recognized in AEP’s 2017 statement of income. Construction activities at Racine continued throughout 2018, accumulating new capital expenditures of $35 million as of September 30, 2018. However, 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 present condition, was $0 as of September 30, 2018. As a result, AEP recorded a pretax impairment of $35 million in Other Operation on the statement of income in the third quarter of 2018. In October 2018, AEP received authorization from the FERC to restart generation at Racine. Management plans to resume generation at Racine during the fourth quarter of 2018. In the first quarter of 2017, AEP recorded a pretax impairment of $4 million in Other Operation on the statement of income related to the Merchant Coal-fired Generation Assets. In addition, AEP recorded a $7 million pretax impairment in Other Operation on the statement of income related to the sale of Zimmer Plant.

Benefit Plans

Benefit Plans	9 Months Ended
	Sep. 30, 2018
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, 2018 2017 2018 2017 (in millions) Service Cost $ 24.4 $ 24.1 $ 2.9 $ 2.8 Interest Cost 46.9 50.7 11.8 14.8 Expected Return on Plan Assets (72.6 ) (71.1 ) (25.6 ) (25.3 ) Amortization of Prior Service Cost (Credit) — 0.3 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.3 20.7 2.7 9.2 Net Periodic Benefit Cost (Credit) $ 20.0 $ 24.7 $ (25.5 ) $ (15.8 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 73.2 $ 72.3 $ 8.7 $ 8.4 Interest Cost 140.8 152.3 35.5 44.5 Expected Return on Plan Assets (217.7 ) (213.5 ) (76.7 ) (76.0 ) Amortization of Prior Service Cost (Credit) — 0.8 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 63.9 62.1 7.9 27.5 Net Periodic Benefit Cost (Credit) $ 60.2 $ 74.0 $ (76.4 ) $ (47.4 ) AEP Texas Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.3 Interest Cost 4.0 4.3 0.9 1.2 Expected Return on Plan Assets (6.4 ) (6.2 ) (2.1 ) (2.2 ) Amortization of Prior Service Credit — — (1.5 ) (1.5 ) Amortization of Net Actuarial Loss 1.8 1.7 0.2 0.8 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (2.2 ) $ (1.4 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 6.9 $ 6.4 $ 0.7 $ 0.7 Interest Cost 12.0 12.9 2.8 3.7 Expected Return on Plan Assets (19.2 ) (18.8 ) (6.4 ) (6.6 ) Amortization of Prior Service Credit — — (4.4 ) (4.4 ) Amortization of Net Actuarial Loss 5.4 5.2 0.6 2.4 Net Periodic Benefit Cost (Credit) $ 5.1 $ 5.7 $ (6.7 ) $ (4.2 ) APCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.4 $ 2.3 $ 0.3 $ 0.3 Interest Cost 5.8 6.5 2.1 2.6 Expected Return on Plan Assets (9.1 ) (8.9 ) (4.0 ) (4.1 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 0.4 1.6 Net Periodic Benefit Cost (Credit) $ 1.7 $ 2.5 $ (3.7 ) $ (2.1 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 7.0 $ 7.0 $ 0.8 $ 0.8 Interest Cost 17.6 19.3 6.2 7.9 Expected Return on Plan Assets (27.4 ) (26.8 ) (12.0 ) (12.3 ) Amortization of Prior Service Cost (Credit) — 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.9 7.8 1.4 4.7 Net Periodic Benefit Cost (Credit) $ 5.1 $ 7.4 $ (11.1 ) $ (6.4 ) I&M Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 3.4 $ 3.5 $ 0.4 $ 0.4 Interest Cost 5.6 6.1 1.4 1.7 Expected Return on Plan Assets (9.0 ) (8.6 ) (3.1 ) (3.1 ) Amortization of Prior Service Credit — — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 0.3 1.1 Net Periodic Benefit Cost (Credit) $ 2.5 $ 3.4 $ (3.4 ) $ (2.2 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 10.2 $ 10.5 $ 1.2 $ 1.2 Interest Cost 16.6 18.2 4.1 5.2 Expected Return on Plan Assets (26.8 ) (25.9 ) (9.3 ) (9.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (7.1 ) (7.0 ) Amortization of Net Actuarial Loss 7.4 7.3 0.9 3.3 Net Periodic Benefit Cost (Credit) $ 7.4 $ 10.2 $ (10.2 ) $ (6.5 ) OPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.0 $ 1.8 $ 0.2 $ 0.3 Interest Cost 4.4 4.8 1.3 1.6 Expected Return on Plan Assets (7.2 ) (6.9 ) (2.9 ) (3.0 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 0.3 1.1 Net Periodic Benefit Cost (Credit) $ 1.2 $ 1.7 $ (2.8 ) $ (1.7 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 5.8 $ 5.6 $ 0.7 $ 0.7 Interest Cost 13.3 14.5 3.9 5.0 Expected Return on Plan Assets (21.6 ) (20.9 ) (8.8 ) (9.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.0 5.9 0.8 3.3 Net Periodic Benefit Cost (Credit) $ 3.5 $ 5.2 $ (8.6 ) $ (5.2 ) PSO Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 1.7 $ 1.7 $ 0.1 $ 0.2 Interest Cost 2.5 2.6 0.6 0.8 Expected Return on Plan Assets (4.0 ) (3.9 ) (1.3 ) (1.4 ) Amortization of Prior Service Credit — — (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.1 0.5 Net Periodic Benefit Cost (Credit) $ 1.3 $ 1.5 $ (1.6 ) $ (1.0 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 5.3 $ 4.9 $ 0.5 $ 0.5 Interest Cost 7.4 8.0 1.8 2.4 Expected Return on Plan Assets (12.1 ) (11.8 ) (4.1 ) (4.2 ) Amortization of Prior Service Credit — — (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 0.4 1.5 Net Periodic Benefit Cost (Credit) $ 3.9 $ 4.4 $ (4.6 ) $ (3.0 ) SWEPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.4 $ 2.1 $ 0.2 $ 0.2 Interest Cost 2.8 3.1 0.7 0.9 Expected Return on Plan Assets (4.4 ) (4.2 ) (1.6 ) (1.5 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.3 0.2 0.5 Net Periodic Benefit Cost (Credit) $ 2.1 $ 2.3 $ (1.8 ) $ (1.2 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 7.0 $ 6.5 $ 0.7 $ 0.6 Interest Cost 8.5 9.2 2.1 2.7 Expected Return on Plan Assets (13.1 ) (12.6 ) (4.8 ) (4.7 ) Amortization of Prior Service Credit — — (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.8 3.7 0.5 1.7 Net Periodic Benefit Cost (Credit) $ 6.2 $ 6.8 $ (5.4 ) $ (3.6 )

Business Segments

Business Segments	9 Months Ended
	Sep. 30, 2018
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2018 and 2017 and reportable segment balance sheet information as of September 30, 2018 and December 31, 2017 . 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 Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 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 Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 September 30, 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 $ 44,553.4 $ 17,619.1 $ 8,130.3 $ 864.1 $ 384.8 $ (354.4 ) (b) $ 71,197.3 Accumulated Depreciation and Amortization 13,703.3 3,856.7 244.3 40.1 183.6 (186.4 ) (b) 17,841.6 Total Property Plant and Equipment - Net $ 30,850.1 $ 13,762.4 $ 7,886.0 $ 824.0 $ 201.2 $ (168.0 ) (b) $ 53,355.7 Total Assets $ 38,813.2 $ 16,399.1 $ 9,127.7 $ 2,369.3 $ 4,306.1 (c) $ (3,398.0 ) (b) (d) $ 67,617.4 Long-term Debt Due Within One Year: Nonaffiliated $ 1,306.1 $ 548.5 $ 50.0 $ 0.1 $ (0.5 ) $ — $ 1,904.2 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 11,563.5 5,082.2 2,966.2 (0.3 ) 1,258.2 — 20,869.8 Total Long-term Debt $ 12,919.6 $ 5,630.7 $ 3,016.2 $ 32.0 $ 1,257.7 $ (82.2 ) $ 22,774.0 December 31, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 43,294.4 $ 16,371.2 $ 7,110.2 $ 644.6 $ 374.5 $ (366.4 ) (b) $ 67,428.5 Accumulated Depreciation and Amortization 13,153.4 3,768.3 176.6 75.0 180.6 (186.9 ) (b) 17,167.0 Total Property Plant and Equipment - Net $ 30,141.0 $ 12,602.9 $ 6,933.6 $ 569.6 $ 193.9 $ (179.5 ) (b) $ 50,261.5 Total Assets $ 37,579.7 $ 16,060.7 $ 8,141.8 $ 2,009.8 $ 3,959.1 (c) $ (3,022.0 ) (b) (d) $ 64,729.1 Long-term Debt Due Within One Year: Nonaffiliated $ 1,038.1 $ 663.1 $ 50.0 $ — $ 2.5 $ — $ 1,753.7 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 10,801.4 4,705.4 2,631.3 (0.3 ) 1,281.8 — 19,419.6 Total Long-term Debt $ 11,889.5 $ 5,368.5 $ 2,681.3 $ 31.9 $ 1,284.3 $ (82.2 ) $ 21,173.3 (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 and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (d) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. 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 (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2018 and 2017 and reportable segment balance sheet information as of September 30, 2018 and December 31, 2017 . 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 ) (b) $ 0.5 Interest Expense 19.8 25.7 (25.7 ) (b) 19.8 Income Tax Expense 18.4 (0.8 ) — 17.6 Net Income $ 77.1 $ 1.0 (c) $ — $ 78.1 Three Months Ended September 30, 2017 State Transcos (a) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (a) (in millions) Revenues from: External Customers $ 35.6 $ — $ — $ 35.6 Sales to AEP Affiliates 130.1 — — 130.1 Other Revenues (0.1 ) — — (0.1 ) Total Revenues $ 165.6 $ — $ — $ 165.6 Interest Income $ — $ 19.5 $ (19.3 ) (b) $ 0.2 Interest Expense 17.1 19.3 (19.3 ) (b) 17.1 Income Tax Expense 29.5 — — 29.5 Net Income $ 58.5 $ 0.1 (c) $ — $ 58.6 Nine Months Ended September 30, 2018 State Transcos (a) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (a) (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 ) (b) $ 1.3 Interest Expense 60.7 75.3 (75.3 ) (b) 60.7 Income Tax Expense 63.7 — — 63.7 Net Income $ 243.6 $ 0.6 (c) $ — $ 244.2 Nine Months Ended September 30, 2017 State Transcos (a) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (a) (in millions) Revenues from: External Customers $ 95.7 $ — $ — $ 95.7 Sales to AEP Affiliates 439.1 — — 439.1 Other Revenues — — — — Total Revenues $ 534.8 $ — $ — $ 534.8 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (b) $ 0.5 Interest Expense 50.4 57.6 (57.6 ) (b) 50.4 Income Tax Expense 108.0 0.2 — 108.2 Net Income $ 212.1 $ 0.3 (c) $ — $ 212.4 September 30, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 7,761.6 (a) $ — $ — $ 7,761.6 (a) Accumulated Depreciation and Amortization 234.6 (a) — — 234.6 (a) Total Transmission Property – Net $ 7,527.0 (a) $ — $ — $ 7,527.0 (a) Notes Receivable - Affiliated $ — $ 2,900.0 $ (2,900.0 ) (d) $ — Total Assets $ 7,983.6 (a) $ 2,988.4 (e) $ (2,973.6 ) (f) $ 7,998.4 (a) Total Long-term Debt $ 2,900.0 $ 2,872.6 $ (2,900.0 ) (d) $ 2,872.6 December 31, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,770.5 (a) $ — $ — $ 6,770.5 (a) Accumulated Depreciation and Amortization 152.6 (a) — — 152.6 (a) Total Transmission Property – Net $ 6,617.9 (a) $ — $ — $ 6,617.9 (a) Notes Receivable - Affiliated $ — $ 2,550.4 $ (2,550.4 ) (d) $ — Total Assets $ 7,086.9 (a) $ 2,590.1 (e) $ (2,594.9 ) (f) $ 7,082.1 (a) Total Long-term Debt $ 2,575.0 $ 2,550.4 $ (2,575.0 ) (d) $ 2,550.4 (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters. (b) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (c) Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos. (d) Elimination of intercompany debt. (e) Includes the elimination of AEPTCo Parent’s investments in State Transcos. (f) Primarily relates to the elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging

Derivatives and Hedging	9 Months Ended
	Sep. 30, 2018
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity. The Registrants adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. See Note 2 - New Accounting Pronouncements for additional information. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2018 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 415.7 — 88.7 52.8 8.0 19.0 13.0 Coal Tons 0.2 — — 0.2 — — — Natural Gas MMBtus 84.4 — 8.4 4.9 — — 16.1 Heating Oil and Gasoline Gallons 8.3 1.7 1.6 0.8 2.0 0.8 0.9 Interest Rate USD $ 37.7 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 500.0 $ — $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2017 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 358.7 — 57.4 38.5 10.4 10.3 22.7 Coal Tons 2.0 — — 2.0 — — — Natural Gas MMBtus 53.7 — 1.1 0.7 — — 18.3 Heating Oil and Gasoline Gallons 6.9 1.4 1.3 0.7 1.6 0.7 0.8 Interest Rate USD $ 50.7 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 500.0 $ — $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. AEP netted cash collateral received from third parties against short-term and long-term risk management assets in the amounts of $15 million and $9.4 million as of September 30, 2018 and December 31, 2017 , respectively. AEP netted cash collateral paid to third parties against short-term and long-term risk management liabilities in the amounts of $1 million and $9 million as of September 30, 2018 and December 31, 2017 , respectively. The netted cash collateral from third parties against short-term and long-term risk management assets and netted cash collateral paid to third parties against short-term and long-term risk management liabilities were immaterial for the other Registrants as of September 30, 2018 and December 31, 2017 . 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, 2018 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 359.9 $ 29.1 $ — $ 389.0 $ (197.1 ) $ 191.9 Long-term Risk Management Assets 295.3 10.6 — 305.9 (41.0 ) 264.9 Total Assets 655.2 39.7 — 694.9 (238.1 ) 456.8 Current Risk Management Liabilities 232.4 7.5 0.5 240.4 (183.1 ) 57.3 Long-term Risk Management Liabilities 240.0 55.4 33.7 329.1 (41.9 ) 287.2 Total Liabilities 472.4 62.9 34.2 569.5 (225.0 ) 344.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 182.8 $ (23.2 ) $ (34.2 ) $ 125.4 $ (13.1 ) $ 112.3 Fair Value of Derivative Instruments December 31, 2017 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 389.0 $ 17.5 $ 2.5 $ 409.0 $ (282.8 ) $ 126.2 Long-term Risk Management Assets 300.9 6.3 — 307.2 (25.1 ) 282.1 Total Assets 689.9 23.8 2.5 716.2 (307.9 ) 408.3 Current Risk Management Liabilities 334.6 9.0 — 343.6 (282.0 ) 61.6 Long-term Risk Management Liabilities 280.6 58.3 8.6 347.5 (25.5 ) 322.0 Total Liabilities 615.2 67.3 8.6 691.1 (307.5 ) 383.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 74.7 $ (43.5 ) $ (6.1 ) $ 25.1 $ (0.4 ) $ 24.7 AEP Texas Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 APCo Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 106.6 $ (38.2 ) $ 68.4 Long-term Risk Management Assets 6.0 (4.6 ) 1.4 Total Assets 112.6 (42.8 ) 69.8 Current Risk Management Liabilities 39.1 (38.2 ) 0.9 Long-term Risk Management Liabilities 5.5 (4.8 ) 0.7 Total Liabilities 44.6 (43.0 ) 1.6 Total MTM Derivative Contract Net Assets $ 68.0 $ 0.2 $ 68.2 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 75.6 $ (50.7 ) $ 24.9 Long-term Risk Management Assets 2.4 (1.3 ) 1.1 Total Assets 78.0 (52.0 ) 26.0 Current Risk Management Liabilities 50.6 (49.3 ) 1.3 Long-term Risk Management Liabilities 1.4 (1.2 ) 0.2 Total Liabilities 52.0 (50.5 ) 1.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 26.0 $ (1.5 ) $ 24.5 I&M Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 39.4 $ (28.5 ) $ 10.9 Long-term Risk Management Assets 3.7 (2.8 ) 0.9 Total Assets 43.1 (31.3 ) 11.8 Current Risk Management Liabilities 35.2 (28.8 ) 6.4 Long-term Risk Management Liabilities 3.2 (2.8 ) 0.4 Total Liabilities 38.4 (31.6 ) 6.8 Total MTM Derivative Contract Net Assets $ 4.7 $ 0.3 $ 5.0 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 47.2 $ (39.6 ) $ 7.6 Long-term Risk Management Assets 1.6 (0.9 ) 0.7 Total Assets 48.8 (40.5 ) 8.3 Current Risk Management Liabilities 48.5 (45.0 ) 3.5 Long-term Risk Management Liabilities 0.9 (0.8 ) 0.1 Total Liabilities 49.4 (45.8 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.6 ) $ 5.3 $ 4.7 OPCo Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets 0.1 — 0.1 Total Assets 0.7 — 0.7 Current Risk Management Liabilities 5.4 — 5.4 Long-term Risk Management Liabilities 89.8 — 89.8 Total Liabilities 95.2 — 95.2 Total MTM Derivative Contract Net Liabilities $ (94.5 ) $ — $ (94.5 ) Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 6.4 — 6.4 Long-term Risk Management Liabilities 126.0 — 126.0 Total Liabilities 132.4 — 132.4 Total MTM Derivative Contract Net Liabilities $ (131.8 ) $ — $ (131.8 ) PSO Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 18.8 $ (0.3 ) $ 18.5 Long-term Risk Management Assets — — — Total Assets 18.8 (0.3 ) 18.5 Current Risk Management Liabilities 0.9 (0.3 ) 0.6 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.3 ) 0.6 Total MTM Derivative Contract Net Assets $ 17.9 $ — $ 17.9 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 6.6 $ (0.2 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 6.6 (0.2 ) 6.4 Current Risk Management Liabilities 0.2 (0.2 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.2 (0.2 ) — Total MTM Derivative Contract Net Assets $ 6.4 $ — $ 6.4 SWEPCo Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 8.1 $ (1.6 ) $ 6.5 Long-term Risk Management Assets — — — Total Assets 8.1 (1.6 ) 6.5 Current Risk Management Liabilities 1.8 (1.6 ) 0.2 Long-term Risk Management Liabilities 2.6 — 2.6 Total Liabilities 4.4 (1.6 ) 2.8 Total MTM Derivative Contract Net Assets $ 3.7 $ — $ 3.7 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 7.0 $ (0.6 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 7.0 (0.6 ) 6.4 Current Risk Management Liabilities 0.8 (0.6 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.8 (0.6 ) 0.2 Total MTM Derivative Contract Net Assets $ 6.2 $ — $ 6.2 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the 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 For the Three Months Ended September 30, 2017 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 — 0.3 0.2 — — — Other Operation 0.1 0.1 — — 0.1 — — Maintenance 0.1 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 0.1 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 0.4 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the 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 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 — 1.6 0.5 — — — Other Operation 0.5 0.1 — — 0.1 — — Maintenance 0.4 0.1 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 (0.2 ) 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ — $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships: Carrying Amount of the Hedged Assets/(Liabilities) Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 (in millions) Long-Term Debt (a) $ (461.4 ) $ (489.3 ) $ 34.2 $ 6.1 (a) Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively. The pretax effects of fair value hedge accounting on income were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Gain (Loss) on Interest Rate Contracts: Gain (Loss) on Fair Value Hedging Instruments (a) $ (6.3 ) $ 0.1 $ (28.1 ) $ (0.1 ) Gain (Loss) on Fair Value Portion of Long-term Debt (a) 6.3 (0.1 ) 28.1 0.1 (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, 2018 and 2017 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2018 and 2017 , 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, 2018 and 2017 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2017 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2018 SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2018 and 2017 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income. Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2018 December 31, 2017 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Loss Net of Tax $ (22.8 ) $ (12.7 ) $ (28.4 ) $ (13.0 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 14.4 (0.8 ) 5.5 (0.8 ) As of September 30, 2018 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 183 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2018 December 31, 2017 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 $ (4.6 ) $ (1.1 ) $ (4.5 ) $ (0.9 ) APCo 2.0 0.9 2.2 0.7 I&M (11.9 ) (1.6 ) (10.7 ) (1.3 ) OPCo 1.3 1.3 1.9 1.1 PSO 2.4 1.0 2.6 0.8 SWEPCo (3.7 ) (1.5 ) (6.0 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2018 and December 31, 2017 , 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, 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 $ 253.1 $ 0.8 $ 211.2 APCo 0.1 — 0.1 I&M — — — SWEPCo 2.8 — 2.8 December 31, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 243.6 $ 1.3 $ 223.1 APCo 0.6 — 0.5 I&M 0.4 — 0.4 SWEPCo 0.2 — 0.1

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
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 contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2018 December 31, 2017 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 22,774.0 $ 23,869.1 $ 21,173.3 $ 23,649.6 AEP Texas 3,914.4 4,019.2 3,649.3 3,964.8 AEPTCo 2,872.6 2,861.1 2,550.4 2,782.9 APCo 4,061.7 4,629.8 3,980.1 4,782.6 I&M 3,062.4 3,161.9 2,745.1 3,014.7 OPCo 1,716.3 1,941.9 1,719.3 2,064.3 PSO 1,286.9 1,373.4 1,286.5 1,457.1 SWEPCo 3,072.7 3,068.4 2,441.9 2,645.9 Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: September 30, 2018 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 170.4 $ — $ — $ 170.4 Fixed Income Securities – Mutual Funds (b) 105.9 — (2.8 ) 103.1 Equity Securities – Mutual Funds 17.6 22.2 — 39.8 Total Other Temporary Investments $ 293.9 $ 22.2 $ (2.8 ) $ 313.3 December 31, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 220.1 $ — $ — $ 220.1 Fixed Income Securities – Mutual Funds (b) 104.3 — (1.4 ) 102.9 Equity Securities – Mutual Funds 17.0 19.7 — 36.7 Total Other Temporary Investments $ 341.4 $ 19.7 $ (1.4 ) $ 359.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.8 12.6 2.2 13.6 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, 2017 , 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 spent nuclear fuel 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. Upon adoption of ASU 2016-01 in first quarter 2018, equity securities are now recorded with changes in fair value recognized in earnings. Effective January 2018 available for sale classification only applies to investment in debt 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, 2018 December 31, 2017 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 41.6 $ — $ — $ 17.2 $ — $ — Fixed Income Securities: United States Government 951.9 12.2 (6.2 ) 981.2 29.7 (3.6 ) Corporate Debt 54.4 1.1 (1.6 ) 58.7 3.8 (1.2 ) State and Local Government 8.5 0.5 (0.2 ) 8.8 0.8 (0.2 ) Subtotal Fixed Income Securities 1,014.8 13.8 (8.0 ) 1,048.7 34.3 (5.0 ) Equity Securities - Domestic (a) 1,609.6 990.5 — 1,461.7 868.2 (75.5 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,666.0 $ 1,004.3 $ (8.0 ) $ 2,527.6 $ 902.5 $ (80.5 ) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $995.8 million and unrealized losses of $5.3 million . AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values. The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Proceeds from Investment Sales $ 513.1 $ 519.5 $ 1,550.9 $ 1,808.6 Purchases of Investments 521.2 525.0 1,589.0 1,842.2 Gross Realized Gains on Investment Sales 3.9 9.8 27.7 198.1 Gross Realized Losses on Investment Sales 3.5 5.2 22.2 145.4 The base cost of fixed income securities was $1 billion and $1 billion as of September 30, 2018 and December 31, 2017 , respectively. The base cost of equity securities was $619 million and $594 million as of September 30, 2018 and December 31, 2017 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2018 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 348.7 After 1 year through 5 years 331.4 After 5 years through 10 years 177.0 After 10 years 157.7 Total $ 1,014.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 160.8 $ — $ — $ 9.6 $ 170.4 Fixed Income Securities – Mutual Funds 103.1 — — — 103.1 Equity Securities – Mutual Funds (b) 39.8 — — — 39.8 Total Other Temporary Investments 303.7 — — 9.6 313.3 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.7 270.9 361.7 (213.2 ) 421.1 Cash Flow Hedges: Commodity Hedges (c) — 20.9 11.7 3.1 35.7 Total Risk Management Assets 1.7 291.8 373.4 (210.1 ) 456.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 27.2 — — 14.4 41.6 Fixed Income Securities: United States Government — 951.9 — — 951.9 Corporate Debt — 54.4 — — 54.4 State and Local Government — 8.5 — — 8.5 Subtotal Fixed Income Securities — 1,014.8 — — 1,014.8 Equity Securities – Domestic (b) 1,609.6 — — — 1,609.6 Total Spent Nuclear Fuel and Decommissioning Trusts 1,636.8 1,014.8 — 14.4 2,666.0 Total Assets $ 1,942.2 $ 1,306.6 $ 373.4 $ (186.1 ) $ 3,436.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 1.9 $ 271.4 $ 178.2 $ (200.1 ) $ 251.4 Cash Flow Hedges: Commodity Hedges (c) — 21.8 34.0 3.1 58.9 Fair Value Hedges — 34.2 — — 34.2 Total Risk Management Liabilities $ 1.9 $ 327.4 $ 212.2 $ (197.0 ) $ 344.5 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 183.2 $ — $ — $ 36.9 $ 220.1 Fixed Income Securities – Mutual Funds 102.9 — — — 102.9 Equity Securities – Mutual Funds (b) 36.7 — — — 36.7 Total Other Temporary Investments 322.8 — — 36.9 359.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 3.9 391.2 274.1 (285.4 ) 383.8 Cash Flow Hedges: Commodity Hedges (c) — 17.3 4.7 — 22.0 Fair Value Hedges — 2.5 — — 2.5 Total Risk Management Assets 3.9 411.0 278.8 (285.4 ) 408.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities – Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,795.9 $ 1,459.7 $ 278.8 $ (238.8 ) $ 3,295.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 5.1 $ 392.5 $ 196.9 $ (285.0 ) $ 309.5 Cash Flow Hedges: Commodity Hedges (c) — 23.9 41.6 — 65.5 Fair Value Hedges — 8.6 — — 8.6 Total Risk Management Liabilities $ 5.1 $ 425.0 $ 238.5 $ (285.0 ) $ 383.6 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 124.2 $ — $ — $ — $ 124.2 Risk Management Assets Risk Management Commodity Contracts (c) — 0.5 — — 0.5 Total Assets $ 124.2 $ 0.5 $ — $ — $ 124.7 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 155.2 $ — $ — $ — $ 155.2 Risk Management Assets Risk Management Commodity Contracts (c) — 0.5 — — 0.5 Total Assets $ 155.2 $ 0.5 $ — $ — $ 155.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 9.9 $ — $ — $ — $ 9.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) 0.2 41.8 66.7 (38.9 ) 69.8 Total Assets $ 10.1 $ 41.8 $ 66.7 $ (38.9 ) $ 79.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.3 $ 40.2 $ 0.2 $ (39.1 ) $ 1.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 16.3 $ — $ — $ — $ 16.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 52.5 25.1 (51.6 ) 26.0 Total Assets $ 16.3 $ 52.5 $ 25.1 $ (51.6 ) $ 42.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 51.2 $ 0.4 $ (50.1 ) $ 1.5 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ 0.1 $ 28.5 $ 12.3 $ (29.1 ) $ 11.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 27.2 — — 14.4 41.6 Fixed Income Securities: United States Government — 951.9 — — 951.9 Corporate Debt — 54.4 — — 54.4 State and Local Government — 8.5 — — 8.5 Subtotal Fixed Income Securities — 1,014.8 — — 1,014.8 Equity Securities - Domestic (b) 1,609.6 — — — 1,609.6 Total Spent Nuclear Fuel and Decommissioning Trusts 1,636.8 1,014.8 — 14.4 2,666.0 Total Assets $ 1,636.9 $ 1,043.3 $ 12.3 $ (14.7 ) $ 2,677.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.1 $ 33.2 $ 2.9 $ (29.4 ) $ 6.8 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 39.4 $ 9.1 $ (40.2 ) $ 8.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities - Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,469.2 $ 1,088.1 $ 9.1 $ (30.5 ) $ 2,535.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 47.6 $ 1.5 $ (45.5 ) $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 15.2 $ — $ — $ — $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.7 — — 0.7 Total Assets $ 15.2 $ 0.7 $ — $ — $ 15.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 95.2 $ — $ 95.2 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ — $ — $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 132.4 $ — $ 132.4 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 18.5 $ (0.3 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.9 $ (0.3 ) $ 0.6 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 6.4 $ (0.2 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.2 $ (0.2 ) $ — SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 7.9 $ (1.6 ) $ 6.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.4 $ (1.6 ) $ 2.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 6.7 $ (0.6 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.8 $ (0.6 ) $ 0.2 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(2) million in 2018 and $(2) million in periods 2019-2021 and $3 million in periods 2022-2023; Level 3 matures $40 million in 2018, $122 million in periods 2019-2021, $21 million in periods 2022-2023 and $1 million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2018 and 2017 . 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, 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 Three Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (c) (d) 5.7 — — — — — Transfers out of Level 3 (d) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 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 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (c) (d) 16.1 — — — — — Transfers out of Level 3 (d) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2018 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 251.5 $ 202.4 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 161.90 $ 33.54 Counterparty Credit Risk (b) 10 418 158 Natural Gas Contracts — 2.8 Discounted Cash Flow Forward Market Price (c) 2.19 2.97 2.45 FTRs 121.9 7.0 Discounted Cash Flow Forward Market Price (a) (9.40 ) 16.17 0.83 Total $ 373.4 $ 212.2 Significant Unobservable Inputs December 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 225.1 $ 233.7 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 263.00 $ 36.32 Counterparty Credit Risk (b) 8 456 180 Natural Gas Contracts — 0.2 Discounted Cash Flow Forward Market Price (c) 2.37 2.96 2.62 FTRs 53.7 4.6 Discounted Cash Flow Forward Market Price (a) (55.62 ) 54.88 0.41 Total $ 278.8 $ 238.5 Significant Unobservable Inputs September 30, 2018 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 14.98 $ 59.45 $ 36.30 FTRs 64.9 0.1 Discounted Cash Flow Forward Market Price 0.06 12.73 2.37 Total $ 66.7 $ 0.2 Significant Unobservable Inputs December 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.4 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 24.3 — Discounted Cash Flow Forward Market Price (0.36 ) 7.15 1.62 Total $ 25.1 $ 0.4 Significant Unobservable Inputs September 30, 2018 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.1 $ 0.9 Discounted Cash Flow Forward Market Price $ 14.98 $ 59.45 $ 36.30 FTRs 11.2 2.0 Discounted Cash Flow Forward Market Price (2.58 ) 6.21 0.73 Total $ 12.3 $ 2.9 Significant Unobservable Inputs December 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.5 $ 0.3 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 8.6 1.2 Discounted Cash Flow Forward Market Price (0.36 ) 5.75 0.86 Total $ 9.1 $ 1.5 Significant Unobservable Inputs September 30, 2018 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 95.2 Discounted Cash Flow Forward Market Price (a) $ 27.23 $ 64.61 $ 43.26 Counterparty Credit Risk (b) 10 188 141 Total $ — $ 95.2 Significant Unobservable Inputs December 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 132.4 Discounted Cash Flow Forward Market Price (a) $ 30.52 $ 170.43 $ 44.62 Counterparty Credit Risk (b) 8 190 136 Total $ — $ 132.4 Significant Unobservable Inputs September 30, 2018 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 18.5 $ 0.9 Discounted Cash Flow Forward Market Price $ (9.40 ) $ 10.30 $ (1.49 ) Significant Unobservable Inputs December 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 6.4 $ 0.2 Discounted Cash Flow Forward Market Price $ (6.62 ) $ 1.41 $ (0.76 ) Significant Unobservable Inputs September 30, 2018 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 2.8 Discounted Cash Flow Forward Market Price (c) $ 2.19 $ 2.97 $ 2.45 FTRs 7.9 1.6 Discounted Cash Flow Forward Market Price (a) (9.40 ) 10.30 (1.49 ) Total $ 7.9 $ 4.4 Significant Unobservable Inputs December 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 0.2 Discounted Cash Flow Forward Market Price (c) $ 2.37 $ 2.96 $ 2.62 FTRs 6.7 0.6 Discounted Cash Flow Forward Market Price (a) (6.62 ) 1.41 (0.76 ) Total $ 6.7 $ 0.8 (a) Represents market prices in dollars per MWh. (b) Re

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Federal Tax Reform In December 2017, Tax Reform legislation was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, and had a material impact on the Registrants’ financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income tax rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, impact bonus depreciation for certain property acquired and placed in service after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits. Provisional Amounts The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued by the SEC staff in December 2017, and made reasonable estimates for the measurement and accounting of the effects of Tax Reform which are reflected in the financial statements as provisional amounts based on the best information available. SAB 118 provides for up to a one-year period to complete the required analysis and accounting for Tax Reform referred to as the measurement period. While the Registrants were able to make reasonable estimates of the impact of Tax Reform in 2017, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative differences or as a result of additional guidance or technical corrections that may be issued by the IRS that may impact management’s interpretation and assumptions utilized. The measurement period adjustments recorded during the third quarter of 2018 to the provisional amounts were immaterial. During the third quarter of 2018, the IRS proposed new regulations that reflect changes made by Tax Reform and affect taxpayers with qualified depreciable property acquired and placed in service after September 27, 2017. The Registrants expect to complete the analysis of the provisional items, including analysis of the new regulations proposed by the IRS, during the fourth quarter of 2018. Status of Tax Reform Regulatory Proceedings The table below summarizes the current status of Tax Reform in AEP’s various regulatory jurisdictions. 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 To be addressed in a later filing To be addressed in a later filing APCo (Virginia) Legislation Enacted – Case Pending (b) Legislation Enacted – Case Pending (b) Order Issued – Partial; Separate Case Pending (c) APCo (West Virginia) Order Issued Order Issued Order Issued I&M (Indiana) Order Issued Order Issued Order Issued I&M (Michigan) Order Issued; Separate Case Pending (d) Case Pending Case Pending AEP (Tennessee) Case Pending Case Pending Case Pending AEP (Kentucky) Order Issued Order Issued Order Issued OPCo (Ohio) Order Issued Order Issued Order Issued PSO (Oklahoma) Order Issued Order Issued Order Issued SWEPCo (Arkansas) Order Issued Order Issued Order Issued SWEPCo (Louisiana) Case Pending – Rates Implemented (e) Case Pending – Rates Implemented (e) Case Pending – Rates Implemented (e) SWEPCo (Texas) Order Issued (f) To be addressed in a later filing To be addressed in a later filing PJM FERC Transmission Settlement Approved (g) Settlement Approved (g) Settlement Approved (g) SPP FERC Transmission To be addressed in a later filing To be addressed in a later filing To be addressed in a later filing (a) A portion of the Excess ADIT that is not subject to rate normalization requirements is to be addressed in a later filing. (b) Legislation has been issued for a blanket amount that is subject to true-up and final commission approval. (c) In October 2018, the Virginia SCC issued an order approving APCo’s request to refund a portion of the Excess ADIT that is not subject to rate normalization requirements to customers. The remainder is to be addressed in a separate pending case. (d) A rider was implemented to refund the impact of Tax Reform prospectively and effective September 1, 2018. A separate filing was submitted in October 2018 for the Tax Reform impact from January 1, 2018 through August 31, 2018. (e) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval. (f) An interim order has been issued to lower rates. Parties continue to finalize settlement. (g) An administrative law judge has approved a settlement. The settlement is subject to final FERC ruling. Reduction in the Corporate Federal Income Tax Rate - Pending Rate Reductions State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. As described in Note 4 - Rate Matters, certain Registrants have received state utility commission orders and have reflected the lower corporate federal income tax rate in current customer rates. The table below provides a summary of the estimated provisions for revenue refund recorded by the Registrants related to the reduction in the corporate federal tax rate as of September 30, 2018 : AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Included in Current Liabilities $ 51.1 $ — $ — $ 40.5 $ 2.0 $ — $ 2.4 $ 5.3 Included in Deferred Credits and Other Noncurrent Liabilities 98.4 21.9 8.6 3.7 12.8 20.8 2.3 27.6 Excess ADIT - Pending Rate Reductions As of September 30, 2018, the Registrants have approximately $4.3 billion of Excess ADIT, as well as an incremental liability of $1.1 billion to reflect the $4.3 billion Excess ADIT on a pretax basis, presented in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets. The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. As of September 30, 2018, approximately $3.4 billion of the Excess ADIT relates to temporary differences associated with certain depreciable property subject to rate normalization requirements. As reflected in the Registrants’ respective estimated annual ETR for 2018, AEP’s regulated public utilities began amortizing the Excess ADIT associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. The amortization resulted in a reduction in the Excess ADIT balance recorded in Regulatory Liabilities and Deferred Investment Tax Credits and a reduction in Income Tax Expense. As a result of state utility commission orders or instructions, the Registrants have recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT to the extent not yet reflected in current customer rates. The table below provides a summary of the estimated provisions for revenue refund recorded by the Registrants as of September 30, 2018 : AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Included in Current Liabilities $ 15.3 $ — $ — $ 9.5 $ — $ — $ 4.7 $ 1.2 Included in Deferred Credits and Other Noncurrent Liabilities 20.6 6.9 0.1 0.7 1.4 3.3 — 7.8 In addition, with respect to the remaining $0.9 billion of Excess ADIT recorded in Regulatory Liabilities and Deferred Investment Tax Credits that are not subject to rate normalization requirements, the Registrants have received state utility commission orders or instructions and a filed FERC settlement agreement to begin amortization. Effective Tax Rates (ETR) The Registrants’ interim ETR reflect the estimated annual ETR for 2018 and 2017 , adjusted for tax expense associated with certain discrete items. As previously mentioned, effective January 1, 2018, Tax Reform lowered the corporate tax rate from 35% to 21%. The interim ETR differ from the federal statutory tax rate of 21% and 35% in 2018 and 2017, respectively, primarily due to state income taxes, the amortization of the Excess ADIT, tax credits and other book/tax differences which are accounted for on a flow-through basis. The ETR for each of the Registrants is included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 AEP (16.2 )% 33.0 % 5.6 % 35.3 % AEP Texas 12.6 % 32.2 % 14.9 % 33.6 % AEPTCo (a) 18.4 % 33.5 % 20.7 % 33.8 % APCo (962.2 )% 33.4 % (13.8 )% 35.5 % I&M 15.9 % 30.6 % 10.4 % 30.1 % OPCo (46.4 )% 36.9 % 4.6 % 35.6 % PSO 5.6 % 37.2 % 8.7 % 37.4 % SWEPCo 9.8 % 21.2 % 11.4 % 25.7 % (a) The 2017 ETRs presented above reflect the revisions made to AEPTCo's previously issued financial statements. See Note 1 - Significant Accounting Matters for additional information. AEP Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the discrete impact of the West Virginia and Ohio Tax Reform orders which enabled APCo, OPCo and WPCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances. The West Virginia and Ohio Tax Reform orders impacted the ETR by (17.9)% and (7.8)% , respectively. See “West Virginia Tax Reform” and “Ohio Tax Reform” sections of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (7.4)% due to increased 2018 amortization of Excess ADIT. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the discrete impact of the West Virginia and Ohio Tax Reform orders which enabled APCo, OPCo and WPCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances. The West Virginia and Ohio Tax Reform orders impacted the ETR by (5.4)% and (2.3)% , respectively. See “West Virginia Tax Reform” and “Ohio Tax Reform” sections of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, state tax legislation enacted in Kentucky in April 2018 impacted the ETR by (1.1)% and increased 2018 amortization of Excess ADIT impacted the ETR by (4.7)% . AEP Texas Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. AEPTCo Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform. APCo Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the discrete impact of the West Virginia Tax Reform orders which enabled APCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances. The West Virginia Tax Reform order impacted the ETR by (887.8)% . See “West Virginia Tax Reform” section of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (31.7)% due to increased 2018 amortization of Excess ADIT. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the discrete impact of the West Virginia Tax Reform orders which enabled APCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances. The West Virginia Tax Reform order impacted the ETR by (28.6)% . See “West Virginia Tax Reform” section of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (4.9)% due to increased 2018 amortization of Excess ADIT. I&M Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, increased 2018 amortization of Excess ADIT and decreased state income taxes. These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, increased 2018 amortization of Excess ADIT and decreased state income taxes. These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028. OPCo Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the discrete impact of the Ohio Tax Reform orders which enabled OPCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances. The Ohio Tax Reform order impacted the ETR by (62.0)% . See “Ohio Tax Reform” section of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (4.1)% due to increased 2018 amortization of Excess ADIT. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the discrete impact of the Ohio Tax Reform orders which enabled OPCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances. The Ohio Tax Reform order impacted the ETR by (15.1)% . See “Ohio Tax Reform” section of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (2.5)% due to increased 2018 amortization of Excess ADIT. PSO Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (17.3)% . Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (13.9)% . SWEPCo Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (9.0)% . These decreases are partially offset by a prior year income tax benefit attributable to SWEPCo’s noncontrolling interest in Sabine. Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (7.9)% . Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011 through 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. To resolve the issue under consideration, AEP and subsidiaries and the IRS exam team agreed to utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015. In June 2018, AEP settled all outstanding issues under audit for tax years 2011-2013, and the audit was again submitted to the Joint Committee for approval in the third quarter of 2018. As a result, the related $72 million unrecognized tax benefit was reversed in the second quarter of 2018. The settlement did not materially impact the Registrants net income, cash flows or financial condition. In the third quarter of 2018, AEP was notified that the IRS would commence an audit of the 2016 tax year in October 2018. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, 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 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.

Financing Activities

Financing Activities	9 Months Ended
	Sep. 30, 2018
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt September 30, 2018 December 31, 2017 (in millions) Senior Unsecured Notes $ 18,342.1 $ 16,478.3 Pollution Control Bonds 1,643.2 1,621.7 Notes Payable 233.2 260.8 Securitization Bonds 1,145.2 1,416.5 Spent Nuclear Fuel Obligation (a) 272.1 268.6 Other Long-term Debt 1,138.2 1,127.4 Total Long-term Debt Outstanding 22,774.0 21,173.3 Long-term Debt Due Within One Year 1,904.2 1,753.7 Long-term Debt $ 20,869.8 $ 19,419.6 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $316 million and $312 million as of September 30, 2018 and December 31, 2017 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2018 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEP Texas Senior Unsecured Notes $ 500.0 3.95 2028 AEPTCo Senior Unsecured Notes 325.0 4.25 2048 APCo Pollution Control Bonds 104.4 2.625 2022 I&M Other Long-term Debt 200.0 Variable 2021 I&M Notes Payable 55.5 Variable 2022 I&M Pollution Control Bonds 100.0 3.05 2025 I&M Senior Unsecured Notes 350.0 3.85 2028 I&M Senior Unsecured Notes 475.0 4.25 2048 OPCo Senior Unsecured Notes 400.0 4.15 2048 SWEPCo Senior Unsecured Notes 575.0 4.10 2028 SWEPCo Senior Unsecured Notes 450.0 3.85 2048 Non-Registrant: Transource Energy Other Long-term Debt 12.7 Variable 2020 WPCo Pollution Control Bonds 65.0 3.00 2022 Total Issuances $ 3,612.6 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) AEP Texas Securitization Bonds $ 70.0 5.17 2018 AEP Texas Senior Unsecured Notes 30.0 5.89 2018 AEP Texas Securitization Bonds 27.6 1.976 2020 AEP Texas Securitization Bonds 104.1 5.306 2020 APCo Securitization Bonds 24.0 2.008 2023 I&M Other Long-term Debt 200.0 Variable 2018 I&M Pollution Control Bonds 100.0 1.75 2018 I&M Senior Unsecured Notes 475.0 7.00 2019 I&M Notes Payable 3.5 Variable 2019 I&M Notes Payable 10.1 Variable 2019 I&M Notes Payable 18.8 Variable 2020 I&M Notes Payable 19.5 Variable 2021 I&M Notes Payable 21.3 Variable 2022 I&M Notes Payable 6.7 Variable 2022 I&M Other Long-term Debt 1.2 6.00 2025 OPCo Senior Unsecured Notes 350.0 6.05 2018 OPCo Securitization Bonds 46.9 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Pollution Control Bonds 81.7 4.95 2018 SWEPCo Senior Unsecured Notes 300.0 5.875 2018 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.2 4.28 2023 SWEPCo Notes Payable 3.2 4.58 2032 Non-Registrant: AEP Energy Notes Payable 0.1 5.75 2019 WPCo Pollution Control Bonds 65.0 Variable 2018 Total Retirements and Principal Payments $ 1,959.5 As of September 30, 2018 , 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 2018, I&M retired $4 million of Notes Payable related to DCC Fuel. 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 immaterial as of September 30, 2018 . The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain 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 the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2018 and December 31, 2017 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the nine months ended September 30, 2018 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, 2018 Limit (in millions) AEP Texas $ 390.6 $ 106.9 $ 189.9 $ 47.1 $ (77.8 ) $ 500.0 AEPTCo 371.3 232.7 237.9 28.1 232.7 795.0 (a) APCo 295.5 23.7 185.3 23.4 (75.4 ) 600.0 I&M 322.1 657.8 257.6 116.4 72.5 500.0 OPCo 270.8 225.0 169.0 189.4 (242.9 ) 500.0 PSO 193.7 30.9 119.8 10.1 (22.0 ) 300.0 SWEPCo 200.1 525.5 143.2 343.3 516.6 350.0 (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, LP are participants in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2018 and December 31, 2017 are included in Advances to Affiliates on each subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity for the nine months ended September 30, 2018 is described in the following table: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Company Money Pool Money Pool September 30, 2018 (in millions) AEP Texas $ 8.4 $ 8.1 $ 8.0 SWEPCo 2.0 2.0 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2018 and December 31, 2017 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2018 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2018 September 30, 2018 Borrowing Limit (in millions) $ 1.1 $ 104.7 $ 1.1 $ 50.0 $ 1.1 $ 45.3 $ 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 were as follows: Nine Months Ended September 30, 2018 2017 Maximum Interest Rate 2.52 % 1.49 % Minimum Interest Rate 1.81 % 0.92 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed from for Funds Loaned to the Utility Money Pool for the the Utility Money Pool for the Nine Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 AEP Texas 2.25 % 1.29 % 2.29 % 1.35 % AEPTCo 2.26 % 1.36 % 2.04 % 1.04 % APCo 2.22 % 1.24 % 2.19 % 1.28 % I&M 2.16 % 1.24 % 2.06 % 1.27 % OPCo 2.18 % 1.40 % 2.47 % 0.98 % PSO 2.25 % 1.30 % 1.86 % — % SWEPCo 2.31 % 1.26 % 1.87 % 0.98 % 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, 2018 Nine Months Ended September 30, 2017 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 2.52 % 1.83 % 2.26 % 1.49 % — % 1.27 % SWEPCo 2.52 % 1.83 % 2.26 % 1.49 % — % 1.27 % 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 2018 2.52 % 1.76 % 2.52 % 1.76 % 2.26 % 2.27 % 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2018 December 31, 2017 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (dollars in millions) AEP Securitized Debt for Receivables (b) $ 750.0 2.06 % $ 718.0 1.22 % AEP Commercial Paper 1,473.2 2.40 % 898.6 1.85 % SWEPCo Notes Payable 19.4 3.45 % 22.0 2.92 % Total Short-term Debt $ 2,242.6 $ 1,638.6 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in July 2018 to include a $125 million and a $625 million facility which expire in July 2020 and 2021, respectively. Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2018 2017 2018 2017 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 2.27 % 1.33 % 2.06 % 1.17 % Net Uncollectible Accounts Receivable Written Off $ 9.6 $ 7.0 $ 19.0 $ 18.2 September 30, 2018 December 31, 2017 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,082.9 $ 925.5 Short-term – Securitized Debt of Receivables 750.0 718.0 Delinquent Securitized Accounts Receivable 58.2 41.1 Bad Debt Reserves Related to Securitization 29.3 28.7 Unbilled Receivables Related to Securitization 242.1 303.2 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except 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 Subsidiaries’ 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, 2018 December 31, 2017 (in millions) APCo $ 122.9 $ 136.2 I&M 169.5 136.5 OPCo 413.7 367.4 PSO 163.0 115.1 SWEPCo 190.5 138.2 The fees paid to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 (in millions) APCo $ 1.8 $ 1.5 $ 5.1 $ 4.2 I&M 2.5 1.8 6.8 4.9 OPCo 7.2 6.1 18.8 16.5 PSO 2.3 2.0 6.0 5.2 SWEPCo 2.6 2.0 6.6 5.4 The proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 (in millions) APCo $ 334.1 $ 335.5 $ 1,079.2 $ 1,029.4 I&M 498.4 409.9 1,401.7 1,218.9 OPCo 695.2 616.3 2,046.9 1,741.7 PSO 454.9 407.0 1,171.2 1,022.6 SWEPCo 512.6 455.0 1,364.6 1,200.8

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2018
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to AEP only. 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. Desert Sky Wind Farm LLC (Desert Sky) and Trent Wind Farm LLC (Trent) (collectively “the LLCs”) were established for the purpose of repowering, owning and operating wind-powered electric energy generation facilities in Texas. In January 2018, AEP admitted a nonaffiliate as a member of the LLCs to own and repower Desert Sky and Trent. The nonaffiliate contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. The nonaffiliates’ contribution of $84 million was recorded as Net Property, Plant and Equipment on the balance sheets, which was the fair value as of the contribution date determined based on key input assumptions of the original cost of the full turbine sets and the discounted cash flow benefit associated with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. AEP owns 79.9% of the LLCs. As a result, management has concluded that Desert Sky and Trent, collectively, are VIE’s and that AEP is the primary beneficiary based on its power to direct the activities that most significantly impact Desert Sky and Trent’s economic performance. Also in January 2018, Desert Sky and Trent entered into a forward PPA for the sale of power to AEPEP related to deliveries of electricity beginning January 1, 2021 for a 12 year period. Prior to the effective date of the PPA, Desert Sky and Trent will sell power at market rates into ERCOT. AEP and the nonaffiliate will share tax attributes including production tax credits and cash distributions from the operation of the LLCs generally consistent with the ownership percentages. See the table below for the classification of Desert Sky and Trent’s assets and liabilities on the balance sheet: American Electric Power Company, Inc. Variable Interest Entities September 30, 2018 Desert Sky and Trent (in millions) ASSETS Current Assets $ 89.2 Net Property, Plant and Equipment 350.8 Other Noncurrent Assets 0.4 Total Assets $ 440.4 LIABILITIES AND EQUITY Current Liabilities $ 93.4 Noncurrent Liabilities 6.1 Equity 340.9 Total Liabilities and Equity $ 440.4 AEP has a call right, which if exercised, would require the nonaffiliate to sell its noncontrolling interest in the LLCs to AEP. The call exercise period is for ninety days, beginning July 2020 for Trent and August 2020 for Desert Sky. The nonaffiliates’ interest in the LLCs is presented as Redeemable Noncontrolling Interest on the balance sheets. The nonaffiliate holds redemption rights, which if exercised, would require AEP to purchase the nonaffiliates’ noncontrolling interest in the LLCs. The redemption right exercise period is for ninety days, beginning July 2021 for Trent and August 2021 for Desert Sky. The exercise price for both the call and redemption right are determined using a discounted cash flow model with agreed input assumptions as well as potential updates to certain assumptions reasonably expected based on the actual results of the LLCs. As of September 30, 2018 , AEP recorded $70 million of Redeemable Noncontrolling Interest in Mezzanine Equity on the balance sheets.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	9 Months Ended
	Sep. 30, 2018
Revenue from Contracts with Customers	REVENUE FROM CONTRACTS WITH CUSTOMERS The disclosures in this note apply to all Registrants, unless indicated otherwise. Disaggregated Revenues from Contracts with Customers The 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, 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 618.5 336.7 — — — — 955.2 Industrial Revenues 573.2 123.9 — — — — 697.1 Other Retail Revenues 49.0 9.8 — — — — 58.8 Total Retail Revenues 2,289.4 1,082.6 — — — — 3,372.0 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 224.2 — — 115.1 — (98.5 ) 240.8 Transmission Revenues (b) 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 (c) 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 (c) 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) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $35 million . The remaining affiliated amounts are immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $147 million . The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. (d) The alternative revenue for Transmission and Distribution Utilities is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. 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 $ 1,711.0 $ — $ — $ — $ — $ 4,617.9 Commercial Revenues 1,693.9 962.6 — — — — 2,656.5 Industrial Revenues 1,655.2 366.8 — — — — 2,022.0 Other Retail Revenues 139.1 29.2 — — — — 168.3 Total Retail Revenues 6,395.1 3,069.6 — — — — 9,464.7 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 686.5 — — 413.4 — (155.2 ) 944.7 Transmission Revenues (b) 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 (c) 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 (c) 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) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $87 million . The remaining affiliated amounts are immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $444 million . The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. (d) The alternative revenue for Transmission and Distribution Utilities is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. The tables below represent revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries: Three Months Ended September 30, 2018 AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 178.8 $ — $ 320.9 $ 207.4 $ 433.5 $ 220.8 $ 214.0 Commercial Revenues 113.7 — 155.6 139.5 222.9 122.2 142.6 Industrial Revenues 27.2 — 157.1 148.7 96.3 80.2 87.5 Other Retail Revenues 6.5 — 19.2 1.7 3.3 24.4 2.2 Total Retail Revenues 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) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $146 million . The remaining affiliated amounts are immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial. (e) The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. (f) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2018 AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 453.6 $ — $ 1,017.2 $ 559.4 $ 1,258.4 $ 531.4 $ 512.3 Commercial Revenues 328.5 — 443.8 373.7 632.8 317.9 378.6 Industrial Revenues 79.7 — 455.9 424.1 287.8 220.4 248.1 Other Retail Revenues 19.1 — 57.6 5.4 9.8 64.9 6.4 Total Retail Revenues 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) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $448 million . The remaining affiliated amounts are immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial. (e) The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. (f) Amounts include affiliated and nonaffiliated revenues. Performance Obligations AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer. The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows: Retail Revenues AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements. Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days. Wholesale Revenues - Generation AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements. AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed. Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenue tables above. APCo has a performance obligation to supply wholesale electricity to KGPCo through a purchased power agreement. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenue tables above. Wholesale Revenues - Transmission AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM. AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenue tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT. APCo, I&M, KGPCo, KPCo, OPCo and WPCo (AEP East Companies) are parties to the Transmission Agreement (TA), which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the Transmission Coordination Agreement (TCA) by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a load serving entity within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenue tables above. Marketing, Competitive Retail and Renewable Revenues AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation. Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly. Fixed Performance Obligations The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2018 . Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues. Company 2018 2019-2020 2021-2022 After 2022 Total (in millions) AEP $ 246.1 $ 258.7 $ 164.8 $ 349.0 $ 1,018.6 AEP Texas 74.2 — — — 74.2 AEPTCo 166.8 — — — 166.8 APCo 30.7 32.9 25.5 11.6 100.7 I&M 6.3 3.0 2.9 1.4 13.6 OPCo 21.5 12.4 — — 33.9 PSO 4.5 — — — 4.5 SWEPCo 9.1 — — — 9.1 Contract Assets and Liabilities Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of September 30, 2018 . When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of September 30, 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, 2018 . See “Securitized Accounts Receivable - AEP Credit” section of Note 12 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, 2018 January 1, 2018 (in millions) AEPTCo $ 71.9 $ 47.1 APCo 54.1 35.6 I&M 24.7 15.1 OPCo 42.5 26.1 PSO 17.1 6.1 SWEPCo 20.3 11.0 Contract Costs Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of September 30, 2018 .

Significant Accounting Matters

Significant Accounting Matters (Policies)	9 Months Ended
	Sep. 30, 2018
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2018 is not necessarily indicative of results that may be expected for the year ending December 31, 2018 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2017 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 22, 2018 .
Earnings Per Share	Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	9 Months Ended
	Sep. 30, 2018
Derivatives and Hedging	Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” 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 Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	9 Months Ended
	Sep. 30, 2018
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 contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and 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. Upon adoption of ASU 2016-01 in first quarter 2018, equity securities are now recorded with changes in fair value recognized in earnings. Effective January 2018 available for sale classification only applies to investment in debt 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.

Variable Interest Entities Vari

Variable Interest Entities Variable Interest Entities (Policies)	9 Months Ended
	Sep. 30, 2018
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

Significant Accounting Matter_2

Significant Accounting Matters (Tables)	9 Months Ended
	Sep. 30, 2018
Basic and Diluted EPS Calculations	Three Months Ended September 30, 2018 2017 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 577.6 $ 544.7 Weighted Average Number of Basic Shares Outstanding 493.0 $ 1.17 491.8 $ 1.11 Weighted Average Dilutive Effect of Stock-Based Awards 0.9 — 1.2 (0.01 ) Weighted Average Number of Diluted Shares Outstanding 493.9 $ 1.17 493.0 $ 1.10 Nine Months Ended September 30, 2018 2017 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,560.4 $ 1,511.9 Weighted Average Number of Basic Shares Outstanding 492.6 $ 3.17 491.8 $ 3.07 Weighted Average Dilutive Effect of Stock-Based Awards 0.9 (0.01 ) 0.6 — Weighted Average Number of Diluted Shares Outstanding 493.5 $ 3.16 492.4 $ 3.07
Revision to Prior Year Income	Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 As Reported Adjustments As Adjusted As Reported Adjustments As Adjusted (in millions) (in millions) TOTAL REVENUES $ 167.3 $ (1.7 ) $ 165.6 $ 549.4 $ (14.6 ) $ 534.8 EXPENSES Depreciation and Amortization 24.8 (0.2 ) 24.6 70.9 (1.2 ) 69.7 TOTAL EXPENSES 72.2 (0.2 ) 72.0 198.5 (1.2 ) 197.3 OPERATING INCOME 95.1 (1.5 ) 93.6 350.9 (13.4 ) 337.5 Other Income (Expense): Allowance for Equity Funds Used During Construction 11.7 (0.3 ) 11.4 36.0 (3.0 ) 33.0 Interest Expense (16.9 ) (0.2 ) (17.1 ) (48.6 ) (1.8 ) (50.4 ) INCOME BEFORE INCOME TAX EXPENSE 90.1 (2.0 ) 88.1 338.8 (18.2 ) 320.6 Income Tax Expense 30.2 (0.7 ) 29.5 114.5 (6.3 ) 108.2 NET INCOME $ 59.9 $ (1.3 ) $ 58.6 $ 224.3 $ (11.9 ) $ 212.4
Schedule of Error Corrections and Prior Period Adjustments	Nine Months Ended September 30, 2017 As Reported Adjustments As Adjusted (in millions) OPERATING ACTIVITIES Net Income $ 224.3 $ (11.9 ) $ 212.4 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 70.9 (1.2 ) 69.7 Deferred Income Taxes 193.0 (1.1 ) 191.9 Allowance for Equity Funds Used During Construction (36.0 ) 3.0 (33.0 ) Change in Other Noncurrent Assets 7.6 1.0 8.6 Changes in Certain Components of Working Capital: Accounts Receivable, Net (44.4 ) 3.6 (40.8 ) Accounts Payable 8.6 11.8 20.4 Accrued Taxes, Net (66.0 ) (5.2 ) (71.2 ) Net Cash Flows from Operating Activities 444.9 — 444.9 INVESTING ACTIVITIES Net Cash Flows Used for Investing Activities (1,277.4 ) — (1,277.4 ) FINANCING ACTIVITIES Net Cash Flows from Financing Activities 832.5 — 832.5 Net Change in Cash and Cash Equivalents — — — Cash and Cash Equivalents at Beginning of Period — — — Cash and Cash Equivalents at End of Period $ — $ — $ — SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 28.6 $ 1.8 $ 30.4 Construction Expenditures Included in Current Liabilities as of September 30, 239.0 9.9 248.9 December 31, 2017 As Reported Adjustment As Adjusted CURRENT ASSETS (in millions) Accounts Receivable: Customers $ 19.1 $ (4.1 ) $ 15.0 Total Accounts Receivable 113.6 (4.1 ) 109.5 Accrued Tax Benefits 46.6 2.8 49.4 TOTAL CURRENT ASSETS 327.7 (1.3 ) 326.4 TRANSMISSION PROPERTY Transmission Property 5,336.1 (16.4 ) 5,319.7 Other Property, Plant and Equipment 131.4 (4.6 ) 126.8 Construction Work in Progress 1,312.7 11.3 1,324.0 Total Transmission Property 6,780.2 (9.7 ) 6,770.5 Accumulated Depreciation and Amortization 170.4 (17.8 ) 152.6 TOTAL TRANSMISSION PROPERTY – NET 6,609.8 8.1 6,617.9 OTHER NONCURRENT ASSETS Deferred Property Taxes 117.8 7.2 125.0 TOTAL OTHER NONCURRENT ASSETS 130.6 7.2 137.8 TOTAL ASSETS $ 7,068.1 $ 14.0 $ 7,082.1 CURRENT LIABILITIES Accounts Payable: General $ 473.2 $ 11.3 $ 484.5 Affiliated Companies 52.9 13.2 66.1 Accrued Taxes 225.4 6.1 231.5 TOTAL CURRENT LIABILITIES 836.3 30.6 866.9 NONCURRENT LIABILITIES Deferred Income Taxes 601.7 (1.3 ) 600.4 Regulatory Liabilities 493.7 0.1 493.8 TOTAL NONCURRENT LIABILITIES 3,626.5 (1.2 ) 3,625.3 TOTAL LIABILITIES 4,462.8 29.4 4,492.2 MEMBER’S EQUITY Retained Earnings 788.7 (15.4 ) 773.3 TOTAL MEMBER’S EQUITY 2,605.3 (15.4 ) 2,589.9 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 7,068.1 $ 14.0 $ 7,082.1
Supplementary Information	September 30, 2018 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 788.3 $ 0.1 $ 2.2 $ 3.5 Restricted Cash 149.2 124.2 9.9 15.2 Total Cash, Cash Equivalents and Restricted Cash $ 937.5 $ 124.3 $ 12.1 $ 18.7 December 31, 2017 AEP AEP Texas APCo OPCo (in millions) Cash and Cash Equivalents $ 214.6 $ 2.0 $ 2.9 $ 3.1 Restricted Cash 198.0 155.2 16.3 26.6 Total Cash, Cash Equivalents and Restricted Cash $ 412.6 $ 157.2 $ 19.2 $ 29.7

Comprehensive Income (Tables)

Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2018
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedges Commodity Interest Rate Pension 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) Credit (5.9 ) 0.4 (1.8 ) (7.3 ) Income Tax (Expense) Credit (1.3 ) 0.1 (0.4 ) (1.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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 Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (0.9 ) — — — (0.9 ) Purchased Electricity for Resale (a) 4.9 — — — 4.9 Interest Expense (a) — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension 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) Credit (23.7 ) 0.9 — (5.1 ) (27.9 ) Income Tax (Expense) Credit (5.0 ) 0.2 — (1.1 ) (5.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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 (b) (6.1 ) (2.7 ) — (8.2 ) (17.0 ) ASU 2016-01 Adoption (b) — — (11.9 ) — (11.9 ) Balance in AOCI as of September 30, 2018 $ (22.8 ) $ (12.7 ) $ — $ (50.5 ) $ (86.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (a) (5.6 ) — — — (5.6 ) Purchased Electricity for Resale (a) 26.0 — — — 26.0 Interest Expense (a) — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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 Amortization of Prior Service Cost (Credit) — — — Amortization of Actuarial (Gains)/Losses — — — Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (4.9 ) $ (9.4 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.3 — 0.3 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) Credit 0.3 0.1 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 0.1 0.3 Net Current Period Other Comprehensive Income (Loss) 0.2 0.1 0.3 Balance in AOCI as of September 30, 2017 $ (4.7 ) $ (9.3 ) $ (14.0 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 1.0 0.1 1.1 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 0.1 0.9 Net Current Period Other Comprehensive Income (Loss) 0.8 0.1 0.9 ASU 2018-02 Adoption (b) (0.9 ) (1.8 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (4.6 ) $ (9.8 ) $ (14.4 ) AEP Texas Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (5.4 ) $ (9.5 ) $ (14.9 ) 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 — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 0.3 1.3 Income Tax (Expense) Credit 0.3 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 0.2 0.9 Net Current Period Other Comprehensive Income (Loss) 0.7 0.2 0.9 Balance in AOCI as of September 30, 2017 $ (4.7 ) $ (9.3 ) $ (14.0 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit (0.4 ) (0.9 ) (1.3 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedges Commodity Interest Rate Pension 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) Credit 0.9 (0.9 ) (2.9 ) (2.9 ) Income Tax (Expense) Credit 0.2 (0.2 ) (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 (b) — 0.5 (0.2 ) 0.3 Balance in AOCI as of September 30, 2018 $ — $ 2.0 $ (3.4 ) $ (1.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Income (Loss) (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income (Loss) 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.2 — 1.2 ASU 2018-02 Adoption (b) (2.4 ) (0.3 ) (2.7 ) Balance in AOCI as of September 30, 2018 $ (11.9 ) $ (1.7 ) $ (13.6 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income (Loss) 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – 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) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Income (Loss) (0.4 ) Balance in AOCI as of September 30, 2018 $ 1.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 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) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Income (Loss) (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 1.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Income (Loss) (1.0 ) ASU 2018-02 Adoption (b) 0.4 Balance in AOCI as of September 30, 2018 $ 1.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Income (Loss) (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – 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) Credit (0.2 ) Income Tax (Expense) Credit — Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2018 $ 2.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Income (Loss) (0.2 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2017 $ 2.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.7 ) Net Current Period Other Comprehensive Income (Loss) (0.7 ) ASU 2018-02 Adoption (b) 0.5 Balance in AOCI as of September 30, 2018 $ 2.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Income (Loss) (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 0.5 (0.4 ) 0.1 Income Tax (Expense) Credit 0.1 (0.1 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2018 Cash Flow Hedge – Interest Rate Pension 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) Credit 1.6 (1.3 ) 0.3 Income Tax (Expense) Credit 0.3 (0.3 ) — Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (1.0 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 3.6 (1.0 ) 2.6 ASU 2018-02 Adoption (b) (1.3 ) 0.4 (0.9 ) Balance in AOCI as of September 30, 2018 $ (3.7 ) $ 1.4 $ (2.3 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedge – Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (a) 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) (a) Amounts reclassified to the referenced line item on the statements of income. (b) See Note 2 - New Accounting Pronouncements for additional information

Rate Matters (Tables)

Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2018
Regulated Generating Unit Expected to be Retired by 2020	Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (dollars in millions) $ 106.5 $ 56.8 $ 49.7 $ 3.1 $ 5.0 2020 28 years
Regulatory Assets Pending Final Regulatory Approval	AEP September 30, December 31, 2018 2017 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 20.1 9.6 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 151.7 128.0 Plant Retirement Costs - Asset Retirement Obligation Costs 39.7 39.7 Cook Plant Uprate Project — 36.3 Cook Plant Turbine — 15.9 Other Regulatory Assets Pending Final Regulatory Approval 18.8 42.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 280.6 $ 322.0 (a) As of September 30, 2018 , AEP Texas has deferred $127 million related to Hurricane Harvey and is in the process of requesting securitization of the distribution portion of the regulatory asset. (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff. AEP Texas September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) $ 150.2 $ 123.3 Rate Case Expense 0.2 0.1 Total Regulatory Assets Pending Final Regulatory Approval $ 150.4 $ 123.4 (a) As of September 30, 2018 , AEP Texas has deferred $127 million related to Hurricane Harvey and is in the process of requesting securitization of the distribution portion of the regulatory asset. APCo September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.0 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 39.7 39.7 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 49.3 $ 49.4 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff. I&M September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ — $ 36.3 Deferred Cook Plant Life Cycle Management Project Costs - Michigan — 14.7 Cook Plant Turbine — 15.9 Rockport Dry Sorbent Injection System - Indiana — 10.4 Other Regulatory Assets Pending Final Regulatory Approval 3.4 2.0 Total Regulatory Assets Pending Final Regulatory Approval $ 3.4 $ 79.3 PSO September 30, December 31, 2018 2017 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Storm-Related Costs $ — $ 3.2 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.1 Total Regulatory Assets Pending Final Regulatory Approval $ 0.5 $ 3.3 SWEPCo September 30, December 31, 2018 2017 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 0.5 0.5 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation - Arkansas, Louisiana 5.0 4.0 Rate Case Expense - Texas 4.6 4.3 Shipe Road Transmission Project - FERC — 3.3 Other Regulatory Assets Pending Final Regulatory Approval 3.3 2.5 Total Regulatory Assets Pending Final Regulatory Approval $ 63.7 $ 64.9

Commitments, Guarantees and C_2

Commitments, Guarantees and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2018
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 71.8 October 2018 to September 2019 AEP Texas 2.8 January 2019 OPCo 0.6 September 2019
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 47.7 AEP Texas 11.4 APCo 8.8 I&M 3.5 OPCo 7.6 PSO 4.1 SWEPCo 4.2

Benefit Plans (Tables)

Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2018
Components of Net Periodic Benefit Cost	AEP Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 24.4 $ 24.1 $ 2.9 $ 2.8 Interest Cost 46.9 50.7 11.8 14.8 Expected Return on Plan Assets (72.6 ) (71.1 ) (25.6 ) (25.3 ) Amortization of Prior Service Cost (Credit) — 0.3 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.3 20.7 2.7 9.2 Net Periodic Benefit Cost (Credit) $ 20.0 $ 24.7 $ (25.5 ) $ (15.8 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 73.2 $ 72.3 $ 8.7 $ 8.4 Interest Cost 140.8 152.3 35.5 44.5 Expected Return on Plan Assets (217.7 ) (213.5 ) (76.7 ) (76.0 ) Amortization of Prior Service Cost (Credit) — 0.8 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 63.9 62.1 7.9 27.5 Net Periodic Benefit Cost (Credit) $ 60.2 $ 74.0 $ (76.4 ) $ (47.4 ) AEP Texas Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.3 Interest Cost 4.0 4.3 0.9 1.2 Expected Return on Plan Assets (6.4 ) (6.2 ) (2.1 ) (2.2 ) Amortization of Prior Service Credit — — (1.5 ) (1.5 ) Amortization of Net Actuarial Loss 1.8 1.7 0.2 0.8 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (2.2 ) $ (1.4 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 6.9 $ 6.4 $ 0.7 $ 0.7 Interest Cost 12.0 12.9 2.8 3.7 Expected Return on Plan Assets (19.2 ) (18.8 ) (6.4 ) (6.6 ) Amortization of Prior Service Credit — — (4.4 ) (4.4 ) Amortization of Net Actuarial Loss 5.4 5.2 0.6 2.4 Net Periodic Benefit Cost (Credit) $ 5.1 $ 5.7 $ (6.7 ) $ (4.2 ) APCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.4 $ 2.3 $ 0.3 $ 0.3 Interest Cost 5.8 6.5 2.1 2.6 Expected Return on Plan Assets (9.1 ) (8.9 ) (4.0 ) (4.1 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 0.4 1.6 Net Periodic Benefit Cost (Credit) $ 1.7 $ 2.5 $ (3.7 ) $ (2.1 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 7.0 $ 7.0 $ 0.8 $ 0.8 Interest Cost 17.6 19.3 6.2 7.9 Expected Return on Plan Assets (27.4 ) (26.8 ) (12.0 ) (12.3 ) Amortization of Prior Service Cost (Credit) — 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.9 7.8 1.4 4.7 Net Periodic Benefit Cost (Credit) $ 5.1 $ 7.4 $ (11.1 ) $ (6.4 ) I&M Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 3.4 $ 3.5 $ 0.4 $ 0.4 Interest Cost 5.6 6.1 1.4 1.7 Expected Return on Plan Assets (9.0 ) (8.6 ) (3.1 ) (3.1 ) Amortization of Prior Service Credit — — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 0.3 1.1 Net Periodic Benefit Cost (Credit) $ 2.5 $ 3.4 $ (3.4 ) $ (2.2 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 10.2 $ 10.5 $ 1.2 $ 1.2 Interest Cost 16.6 18.2 4.1 5.2 Expected Return on Plan Assets (26.8 ) (25.9 ) (9.3 ) (9.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (7.1 ) (7.0 ) Amortization of Net Actuarial Loss 7.4 7.3 0.9 3.3 Net Periodic Benefit Cost (Credit) $ 7.4 $ 10.2 $ (10.2 ) $ (6.5 ) OPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.0 $ 1.8 $ 0.2 $ 0.3 Interest Cost 4.4 4.8 1.3 1.6 Expected Return on Plan Assets (7.2 ) (6.9 ) (2.9 ) (3.0 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 0.3 1.1 Net Periodic Benefit Cost (Credit) $ 1.2 $ 1.7 $ (2.8 ) $ (1.7 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 5.8 $ 5.6 $ 0.7 $ 0.7 Interest Cost 13.3 14.5 3.9 5.0 Expected Return on Plan Assets (21.6 ) (20.9 ) (8.8 ) (9.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.0 5.9 0.8 3.3 Net Periodic Benefit Cost (Credit) $ 3.5 $ 5.2 $ (8.6 ) $ (5.2 ) PSO Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 1.7 $ 1.7 $ 0.1 $ 0.2 Interest Cost 2.5 2.6 0.6 0.8 Expected Return on Plan Assets (4.0 ) (3.9 ) (1.3 ) (1.4 ) Amortization of Prior Service Credit — — (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.1 0.5 Net Periodic Benefit Cost (Credit) $ 1.3 $ 1.5 $ (1.6 ) $ (1.0 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 5.3 $ 4.9 $ 0.5 $ 0.5 Interest Cost 7.4 8.0 1.8 2.4 Expected Return on Plan Assets (12.1 ) (11.8 ) (4.1 ) (4.2 ) Amortization of Prior Service Credit — — (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 0.4 1.5 Net Periodic Benefit Cost (Credit) $ 3.9 $ 4.4 $ (4.6 ) $ (3.0 ) SWEPCo Pension Plans OPEB Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 2.4 $ 2.1 $ 0.2 $ 0.2 Interest Cost 2.8 3.1 0.7 0.9 Expected Return on Plan Assets (4.4 ) (4.2 ) (1.6 ) (1.5 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.3 0.2 0.5 Net Periodic Benefit Cost (Credit) $ 2.1 $ 2.3 $ (1.8 ) $ (1.2 ) Pension Plans OPEB Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Service Cost $ 7.0 $ 6.5 $ 0.7 $ 0.6 Interest Cost 8.5 9.2 2.1 2.7 Expected Return on Plan Assets (13.1 ) (12.6 ) (4.8 ) (4.7 ) Amortization of Prior Service Credit — — (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.8 3.7 0.5 1.7 Net Periodic Benefit Cost (Credit) $ 6.2 $ 6.8 $ (5.4 ) $ (3.6 )

Business Segments (Tables)

Business Segments (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting Information [Line Items]
Reportable Segment Information	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 Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 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 Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 September 30, 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 $ 44,553.4 $ 17,619.1 $ 8,130.3 $ 864.1 $ 384.8 $ (354.4 ) (b) $ 71,197.3 Accumulated Depreciation and Amortization 13,703.3 3,856.7 244.3 40.1 183.6 (186.4 ) (b) 17,841.6 Total Property Plant and Equipment - Net $ 30,850.1 $ 13,762.4 $ 7,886.0 $ 824.0 $ 201.2 $ (168.0 ) (b) $ 53,355.7 Total Assets $ 38,813.2 $ 16,399.1 $ 9,127.7 $ 2,369.3 $ 4,306.1 (c) $ (3,398.0 ) (b) (d) $ 67,617.4 Long-term Debt Due Within One Year: Nonaffiliated $ 1,306.1 $ 548.5 $ 50.0 $ 0.1 $ (0.5 ) $ — $ 1,904.2 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 11,563.5 5,082.2 2,966.2 (0.3 ) 1,258.2 — 20,869.8 Total Long-term Debt $ 12,919.6 $ 5,630.7 $ 3,016.2 $ 32.0 $ 1,257.7 $ (82.2 ) $ 22,774.0 December 31, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 43,294.4 $ 16,371.2 $ 7,110.2 $ 644.6 $ 374.5 $ (366.4 ) (b) $ 67,428.5 Accumulated Depreciation and Amortization 13,153.4 3,768.3 176.6 75.0 180.6 (186.9 ) (b) 17,167.0 Total Property Plant and Equipment - Net $ 30,141.0 $ 12,602.9 $ 6,933.6 $ 569.6 $ 193.9 $ (179.5 ) (b) $ 50,261.5 Total Assets $ 37,579.7 $ 16,060.7 $ 8,141.8 $ 2,009.8 $ 3,959.1 (c) $ (3,022.0 ) (b) (d) $ 64,729.1 Long-term Debt Due Within One Year: Nonaffiliated $ 1,038.1 $ 663.1 $ 50.0 $ — $ 2.5 $ — $ 1,753.7 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Nonaffiliated 10,801.4 4,705.4 2,631.3 (0.3 ) 1,281.8 — 19,419.6 Total Long-term Debt $ 11,889.5 $ 5,368.5 $ 2,681.3 $ 31.9 $ 1,284.3 $ (82.2 ) $ 21,173.3 (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 and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (d) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. 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 ) (b) $ 0.5 Interest Expense 19.8 25.7 (25.7 ) (b) 19.8 Income Tax Expense 18.4 (0.8 ) — 17.6 Net Income $ 77.1 $ 1.0 (c) $ — $ 78.1 Three Months Ended September 30, 2017 State Transcos (a) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (a) (in millions) Revenues from: External Customers $ 35.6 $ — $ — $ 35.6 Sales to AEP Affiliates 130.1 — — 130.1 Other Revenues (0.1 ) — — (0.1 ) Total Revenues $ 165.6 $ — $ — $ 165.6 Interest Income $ — $ 19.5 $ (19.3 ) (b) $ 0.2 Interest Expense 17.1 19.3 (19.3 ) (b) 17.1 Income Tax Expense 29.5 — — 29.5 Net Income $ 58.5 $ 0.1 (c) $ — $ 58.6 Nine Months Ended September 30, 2018 State Transcos (a) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (a) (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 ) (b) $ 1.3 Interest Expense 60.7 75.3 (75.3 ) (b) 60.7 Income Tax Expense 63.7 — — 63.7 Net Income $ 243.6 $ 0.6 (c) $ — $ 244.2 Nine Months Ended September 30, 2017 State Transcos (a) AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (a) (in millions) Revenues from: External Customers $ 95.7 $ — $ — $ 95.7 Sales to AEP Affiliates 439.1 — — 439.1 Other Revenues — — — — Total Revenues $ 534.8 $ — $ — $ 534.8 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (b) $ 0.5 Interest Expense 50.4 57.6 (57.6 ) (b) 50.4 Income Tax Expense 108.0 0.2 — 108.2 Net Income $ 212.1 $ 0.3 (c) $ — $ 212.4 September 30, 2018 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 7,761.6 (a) $ — $ — $ 7,761.6 (a) Accumulated Depreciation and Amortization 234.6 (a) — — 234.6 (a) Total Transmission Property – Net $ 7,527.0 (a) $ — $ — $ 7,527.0 (a) Notes Receivable - Affiliated $ — $ 2,900.0 $ (2,900.0 ) (d) $ — Total Assets $ 7,983.6 (a) $ 2,988.4 (e) $ (2,973.6 ) (f) $ 7,998.4 (a) Total Long-term Debt $ 2,900.0 $ 2,872.6 $ (2,900.0 ) (d) $ 2,872.6 December 31, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,770.5 (a) $ — $ — $ 6,770.5 (a) Accumulated Depreciation and Amortization 152.6 (a) — — 152.6 (a) Total Transmission Property – Net $ 6,617.9 (a) $ — $ — $ 6,617.9 (a) Notes Receivable - Affiliated $ — $ 2,550.4 $ (2,550.4 ) (d) $ — Total Assets $ 7,086.9 (a) $ 2,590.1 (e) $ (2,594.9 ) (f) $ 7,082.1 (a) Total Long-term Debt $ 2,575.0 $ 2,550.4 $ (2,575.0 ) (d) $ 2,550.4 (a) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters. (b) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (c) Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos. (d) Elimination of intercompany debt. (e) Includes the elimination of AEPTCo Parent’s investments in State Transcos. (f) Primarily relates to the elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	9 Months Ended
	Sep. 30, 2018
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2018 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 415.7 — 88.7 52.8 8.0 19.0 13.0 Coal Tons 0.2 — — 0.2 — — — Natural Gas MMBtus 84.4 — 8.4 4.9 — — 16.1 Heating Oil and Gasoline Gallons 8.3 1.7 1.6 0.8 2.0 0.8 0.9 Interest Rate USD $ 37.7 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 500.0 $ — $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2017 Primary Risk Exposure Unit of Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 358.7 — 57.4 38.5 10.4 10.3 22.7 Coal Tons 2.0 — — 2.0 — — — Natural Gas MMBtus 53.7 — 1.1 0.7 — — 18.3 Heating Oil and Gasoline Gallons 6.9 1.4 1.3 0.7 1.6 0.7 0.8 Interest Rate USD $ 50.7 $ — $ — $ — $ — $ — $ — Interest Rate USD $ 500.0 $ — $ — $ — $ — $ — $ —
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments September 30, 2018 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 359.9 $ 29.1 $ — $ 389.0 $ (197.1 ) $ 191.9 Long-term Risk Management Assets 295.3 10.6 — 305.9 (41.0 ) 264.9 Total Assets 655.2 39.7 — 694.9 (238.1 ) 456.8 Current Risk Management Liabilities 232.4 7.5 0.5 240.4 (183.1 ) 57.3 Long-term Risk Management Liabilities 240.0 55.4 33.7 329.1 (41.9 ) 287.2 Total Liabilities 472.4 62.9 34.2 569.5 (225.0 ) 344.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 182.8 $ (23.2 ) $ (34.2 ) $ 125.4 $ (13.1 ) $ 112.3 Fair Value of Derivative Instruments December 31, 2017 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 389.0 $ 17.5 $ 2.5 $ 409.0 $ (282.8 ) $ 126.2 Long-term Risk Management Assets 300.9 6.3 — 307.2 (25.1 ) 282.1 Total Assets 689.9 23.8 2.5 716.2 (307.9 ) 408.3 Current Risk Management Liabilities 334.6 9.0 — 343.6 (282.0 ) 61.6 Long-term Risk Management Liabilities 280.6 58.3 8.6 347.5 (25.5 ) 322.0 Total Liabilities 615.2 67.3 8.6 691.1 (307.5 ) 383.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 74.7 $ (43.5 ) $ (6.1 ) $ 25.1 $ (0.4 ) $ 24.7 AEP Texas Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 APCo Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 106.6 $ (38.2 ) $ 68.4 Long-term Risk Management Assets 6.0 (4.6 ) 1.4 Total Assets 112.6 (42.8 ) 69.8 Current Risk Management Liabilities 39.1 (38.2 ) 0.9 Long-term Risk Management Liabilities 5.5 (4.8 ) 0.7 Total Liabilities 44.6 (43.0 ) 1.6 Total MTM Derivative Contract Net Assets $ 68.0 $ 0.2 $ 68.2 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 75.6 $ (50.7 ) $ 24.9 Long-term Risk Management Assets 2.4 (1.3 ) 1.1 Total Assets 78.0 (52.0 ) 26.0 Current Risk Management Liabilities 50.6 (49.3 ) 1.3 Long-term Risk Management Liabilities 1.4 (1.2 ) 0.2 Total Liabilities 52.0 (50.5 ) 1.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 26.0 $ (1.5 ) $ 24.5 I&M Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 39.4 $ (28.5 ) $ 10.9 Long-term Risk Management Assets 3.7 (2.8 ) 0.9 Total Assets 43.1 (31.3 ) 11.8 Current Risk Management Liabilities 35.2 (28.8 ) 6.4 Long-term Risk Management Liabilities 3.2 (2.8 ) 0.4 Total Liabilities 38.4 (31.6 ) 6.8 Total MTM Derivative Contract Net Assets $ 4.7 $ 0.3 $ 5.0 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 47.2 $ (39.6 ) $ 7.6 Long-term Risk Management Assets 1.6 (0.9 ) 0.7 Total Assets 48.8 (40.5 ) 8.3 Current Risk Management Liabilities 48.5 (45.0 ) 3.5 Long-term Risk Management Liabilities 0.9 (0.8 ) 0.1 Total Liabilities 49.4 (45.8 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.6 ) $ 5.3 $ 4.7 OPCo Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets 0.1 — 0.1 Total Assets 0.7 — 0.7 Current Risk Management Liabilities 5.4 — 5.4 Long-term Risk Management Liabilities 89.8 — 89.8 Total Liabilities 95.2 — 95.2 Total MTM Derivative Contract Net Liabilities $ (94.5 ) $ — $ (94.5 ) Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 6.4 — 6.4 Long-term Risk Management Liabilities 126.0 — 126.0 Total Liabilities 132.4 — 132.4 Total MTM Derivative Contract Net Liabilities $ (131.8 ) $ — $ (131.8 ) PSO Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 18.8 $ (0.3 ) $ 18.5 Long-term Risk Management Assets — — — Total Assets 18.8 (0.3 ) 18.5 Current Risk Management Liabilities 0.9 (0.3 ) 0.6 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.3 ) 0.6 Total MTM Derivative Contract Net Assets $ 17.9 $ — $ 17.9 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 6.6 $ (0.2 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 6.6 (0.2 ) 6.4 Current Risk Management Liabilities 0.2 (0.2 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.2 (0.2 ) — Total MTM Derivative Contract Net Assets $ 6.4 $ — $ 6.4 SWEPCo Fair Value of Derivative Instruments September 30, 2018 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 8.1 $ (1.6 ) $ 6.5 Long-term Risk Management Assets — — — Total Assets 8.1 (1.6 ) 6.5 Current Risk Management Liabilities 1.8 (1.6 ) 0.2 Long-term Risk Management Liabilities 2.6 — 2.6 Total Liabilities 4.4 (1.6 ) 2.8 Total MTM Derivative Contract Net Assets $ 3.7 $ — $ 3.7 Fair Value of Derivative Instruments December 31, 2017 Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) (in millions) Current Risk Management Assets $ 7.0 $ (0.6 ) $ 6.4 Long-term Risk Management Assets — — — Total Assets 7.0 (0.6 ) 6.4 Current Risk Management Liabilities 0.8 (0.6 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.8 (0.6 ) 0.2 Total MTM Derivative Contract Net Assets $ 6.2 $ — $ 6.2 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the 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 For the Three Months Ended September 30, 2017 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 — 0.3 0.2 — — — Other Operation 0.1 0.1 — — 0.1 — — Maintenance 0.1 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 0.1 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 0.4 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the 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 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 — 1.6 0.5 — — — Other Operation 0.5 0.1 — — 0.1 — — Maintenance 0.4 0.1 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 (0.2 ) 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ — $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 (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 Assets/(Liabilities) Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities) September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 (in millions) Long-Term Debt (a) $ (461.4 ) $ (489.3 ) $ 34.2 $ 6.1 (a) Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
Gain (Loss) on Hedging Instruments	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Gain (Loss) on Interest Rate Contracts: Gain (Loss) on Fair Value Hedging Instruments (a) $ (6.3 ) $ 0.1 $ (28.1 ) $ (0.1 ) Gain (Loss) on Fair Value Portion of Long-term Debt (a) 6.3 (0.1 ) 28.1 0.1 (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 AEP’s Balance Sheets September 30, 2018 December 31, 2017 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Loss Net of Tax $ (22.8 ) $ (12.7 ) $ (28.4 ) $ (13.0 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 14.4 (0.8 ) 5.5 (0.8 ) Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2018 December 31, 2017 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 $ (4.6 ) $ (1.1 ) $ (4.5 ) $ (0.9 ) APCo 2.0 0.9 2.2 0.7 I&M (11.9 ) (1.6 ) (10.7 ) (1.3 ) OPCo 1.3 1.3 1.9 1.1 PSO 2.4 1.0 2.6 0.8 SWEPCo (3.7 ) (1.5 ) (6.0 ) (1.4 )
Liabilities Subject to Cross Default Provisions	September 30, 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 $ 253.1 $ 0.8 $ 211.2 APCo 0.1 — 0.1 I&M — — — SWEPCo 2.8 — 2.8 December 31, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 243.6 $ 1.3 $ 223.1 APCo 0.6 — 0.5 I&M 0.4 — 0.4 SWEPCo 0.2 — 0.1

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
Book Values and Fair Values of Long-term Debt	September 30, 2018 December 31, 2017 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 22,774.0 $ 23,869.1 $ 21,173.3 $ 23,649.6 AEP Texas 3,914.4 4,019.2 3,649.3 3,964.8 AEPTCo 2,872.6 2,861.1 2,550.4 2,782.9 APCo 4,061.7 4,629.8 3,980.1 4,782.6 I&M 3,062.4 3,161.9 2,745.1 3,014.7 OPCo 1,716.3 1,941.9 1,719.3 2,064.3 PSO 1,286.9 1,373.4 1,286.5 1,457.1 SWEPCo 3,072.7 3,068.4 2,441.9 2,645.9
Other Temporary Investments	September 30, 2018 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 170.4 $ — $ — $ 170.4 Fixed Income Securities – Mutual Funds (b) 105.9 — (2.8 ) 103.1 Equity Securities – Mutual Funds 17.6 22.2 — 39.8 Total Other Temporary Investments $ 293.9 $ 22.2 $ (2.8 ) $ 313.3 December 31, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash and Other Cash Deposits (a) $ 220.1 $ — $ — $ 220.1 Fixed Income Securities – Mutual Funds (b) 104.3 — (1.4 ) 102.9 Equity Securities – Mutual Funds 17.0 19.7 — 36.7 Total Other Temporary Investments $ 341.4 $ 19.7 $ (1.4 ) $ 359.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
Debt and Equity Securities Within Other Temporary Investments	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.8 12.6 2.2 13.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — —
Nuclear Trust Fund Investments	September 30, 2018 December 31, 2017 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 41.6 $ — $ — $ 17.2 $ — $ — Fixed Income Securities: United States Government 951.9 12.2 (6.2 ) 981.2 29.7 (3.6 ) Corporate Debt 54.4 1.1 (1.6 ) 58.7 3.8 (1.2 ) State and Local Government 8.5 0.5 (0.2 ) 8.8 0.8 (0.2 ) Subtotal Fixed Income Securities 1,014.8 13.8 (8.0 ) 1,048.7 34.3 (5.0 ) Equity Securities - Domestic (a) 1,609.6 990.5 — 1,461.7 868.2 (75.5 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,666.0 $ 1,004.3 $ (8.0 ) $ 2,527.6 $ 902.5 $ (80.5 ) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $995.8 million and unrealized losses of $5.3 million . AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in millions) Proceeds from Investment Sales $ 513.1 $ 519.5 $ 1,550.9 $ 1,808.6 Purchases of Investments 521.2 525.0 1,589.0 1,842.2 Gross Realized Gains on Investment Sales 3.9 9.8 27.7 198.1 Gross Realized Losses on Investment Sales 3.5 5.2 22.2 145.4
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 348.7 After 1 year through 5 years 331.4 After 5 years through 10 years 177.0 After 10 years 157.7 Total $ 1,014.8
Fair Value, Assets and Liabilities Measured on Recurring Basis	AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 160.8 $ — $ — $ 9.6 $ 170.4 Fixed Income Securities – Mutual Funds 103.1 — — — 103.1 Equity Securities – Mutual Funds (b) 39.8 — — — 39.8 Total Other Temporary Investments 303.7 — — 9.6 313.3 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.7 270.9 361.7 (213.2 ) 421.1 Cash Flow Hedges: Commodity Hedges (c) — 20.9 11.7 3.1 35.7 Total Risk Management Assets 1.7 291.8 373.4 (210.1 ) 456.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 27.2 — — 14.4 41.6 Fixed Income Securities: United States Government — 951.9 — — 951.9 Corporate Debt — 54.4 — — 54.4 State and Local Government — 8.5 — — 8.5 Subtotal Fixed Income Securities — 1,014.8 — — 1,014.8 Equity Securities – Domestic (b) 1,609.6 — — — 1,609.6 Total Spent Nuclear Fuel and Decommissioning Trusts 1,636.8 1,014.8 — 14.4 2,666.0 Total Assets $ 1,942.2 $ 1,306.6 $ 373.4 $ (186.1 ) $ 3,436.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 1.9 $ 271.4 $ 178.2 $ (200.1 ) $ 251.4 Cash Flow Hedges: Commodity Hedges (c) — 21.8 34.0 3.1 58.9 Fair Value Hedges — 34.2 — — 34.2 Total Risk Management Liabilities $ 1.9 $ 327.4 $ 212.2 $ (197.0 ) $ 344.5 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments Restricted Cash and Other Cash Deposits (a) $ 183.2 $ — $ — $ 36.9 $ 220.1 Fixed Income Securities – Mutual Funds 102.9 — — — 102.9 Equity Securities – Mutual Funds (b) 36.7 — — — 36.7 Total Other Temporary Investments 322.8 — — 36.9 359.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 3.9 391.2 274.1 (285.4 ) 383.8 Cash Flow Hedges: Commodity Hedges (c) — 17.3 4.7 — 22.0 Fair Value Hedges — 2.5 — — 2.5 Total Risk Management Assets 3.9 411.0 278.8 (285.4 ) 408.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities – Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,795.9 $ 1,459.7 $ 278.8 $ (238.8 ) $ 3,295.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 5.1 $ 392.5 $ 196.9 $ (285.0 ) $ 309.5 Cash Flow Hedges: Commodity Hedges (c) — 23.9 41.6 — 65.5 Fair Value Hedges — 8.6 — — 8.6 Total Risk Management Liabilities $ 5.1 $ 425.0 $ 238.5 $ (285.0 ) $ 383.6 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 124.2 $ — $ — $ — $ 124.2 Risk Management Assets Risk Management Commodity Contracts (c) — 0.5 — — 0.5 Total Assets $ 124.2 $ 0.5 $ — $ — $ 124.7 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 155.2 $ — $ — $ — $ 155.2 Risk Management Assets Risk Management Commodity Contracts (c) — 0.5 — — 0.5 Total Assets $ 155.2 $ 0.5 $ — $ — $ 155.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 9.9 $ — $ — $ — $ 9.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) 0.2 41.8 66.7 (38.9 ) 69.8 Total Assets $ 10.1 $ 41.8 $ 66.7 $ (38.9 ) $ 79.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.3 $ 40.2 $ 0.2 $ (39.1 ) $ 1.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 16.3 $ — $ — $ — $ 16.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 52.5 25.1 (51.6 ) 26.0 Total Assets $ 16.3 $ 52.5 $ 25.1 $ (51.6 ) $ 42.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 51.2 $ 0.4 $ (50.1 ) $ 1.5 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ 0.1 $ 28.5 $ 12.3 $ (29.1 ) $ 11.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 27.2 — — 14.4 41.6 Fixed Income Securities: United States Government — 951.9 — — 951.9 Corporate Debt — 54.4 — — 54.4 State and Local Government — 8.5 — — 8.5 Subtotal Fixed Income Securities — 1,014.8 — — 1,014.8 Equity Securities - Domestic (b) 1,609.6 — — — 1,609.6 Total Spent Nuclear Fuel and Decommissioning Trusts 1,636.8 1,014.8 — 14.4 2,666.0 Total Assets $ 1,636.9 $ 1,043.3 $ 12.3 $ (14.7 ) $ 2,677.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ 0.1 $ 33.2 $ 2.9 $ (29.4 ) $ 6.8 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 39.4 $ 9.1 $ (40.2 ) $ 8.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.5 — — 9.7 17.2 Fixed Income Securities: United States Government — 981.2 — — 981.2 Corporate Debt — 58.7 — — 58.7 State and Local Government — 8.8 — — 8.8 Subtotal Fixed Income Securities — 1,048.7 — — 1,048.7 Equity Securities - Domestic (b) 1,461.7 — — — 1,461.7 Total Spent Nuclear Fuel and Decommissioning Trusts 1,469.2 1,048.7 — 9.7 2,527.6 Total Assets $ 1,469.2 $ 1,088.1 $ 9.1 $ (30.5 ) $ 2,535.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 47.6 $ 1.5 $ (45.5 ) $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 15.2 $ — $ — $ — $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.7 — — 0.7 Total Assets $ 15.2 $ 0.7 $ — $ — $ 15.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 95.2 $ — $ 95.2 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ — $ — $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 132.4 $ — $ 132.4 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 18.5 $ (0.3 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.9 $ (0.3 ) $ 0.6 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 6.4 $ (0.2 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.2 $ (0.2 ) $ — SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2018 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 7.9 $ (1.6 ) $ 6.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.4 $ (1.6 ) $ 2.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 6.7 $ (0.6 ) $ 6.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.8 $ (0.6 ) $ 0.2 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(2) million in 2018 and $(2) million in periods 2019-2021 and $3 million in periods 2022-2023; Level 3 matures $40 million in 2018, $122 million in periods 2019-2021, $21 million in periods 2022-2023 and $1 million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	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 Three Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (c) (d) 5.7 — — — — — Transfers out of Level 3 (d) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 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 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (c) (d) 16.1 — — — — — Transfers out of Level 3 (d) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (e) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 (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 liabilities/assets or accounts payable.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2018 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 251.5 $ 202.4 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 161.90 $ 33.54 Counterparty Credit Risk (b) 10 418 158 Natural Gas Contracts — 2.8 Discounted Cash Flow Forward Market Price (c) 2.19 2.97 2.45 FTRs 121.9 7.0 Discounted Cash Flow Forward Market Price (a) (9.40 ) 16.17 0.83 Total $ 373.4 $ 212.2 Significant Unobservable Inputs December 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 225.1 $ 233.7 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 263.00 $ 36.32 Counterparty Credit Risk (b) 8 456 180 Natural Gas Contracts — 0.2 Discounted Cash Flow Forward Market Price (c) 2.37 2.96 2.62 FTRs 53.7 4.6 Discounted Cash Flow Forward Market Price (a) (55.62 ) 54.88 0.41 Total $ 278.8 $ 238.5 Significant Unobservable Inputs September 30, 2018 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 14.98 $ 59.45 $ 36.30 FTRs 64.9 0.1 Discounted Cash Flow Forward Market Price 0.06 12.73 2.37 Total $ 66.7 $ 0.2 Significant Unobservable Inputs December 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.4 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 24.3 — Discounted Cash Flow Forward Market Price (0.36 ) 7.15 1.62 Total $ 25.1 $ 0.4 Significant Unobservable Inputs September 30, 2018 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.1 $ 0.9 Discounted Cash Flow Forward Market Price $ 14.98 $ 59.45 $ 36.30 FTRs 11.2 2.0 Discounted Cash Flow Forward Market Price (2.58 ) 6.21 0.73 Total $ 12.3 $ 2.9 Significant Unobservable Inputs December 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.5 $ 0.3 Discounted Cash Flow Forward Market Price $ 20.52 $ 195.00 $ 33.80 FTRs 8.6 1.2 Discounted Cash Flow Forward Market Price (0.36 ) 5.75 0.86 Total $ 9.1 $ 1.5 Significant Unobservable Inputs September 30, 2018 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 95.2 Discounted Cash Flow Forward Market Price (a) $ 27.23 $ 64.61 $ 43.26 Counterparty Credit Risk (b) 10 188 141 Total $ — $ 95.2 Significant Unobservable Inputs December 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 132.4 Discounted Cash Flow Forward Market Price (a) $ 30.52 $ 170.43 $ 44.62 Counterparty Credit Risk (b) 8 190 136 Total $ — $ 132.4 Significant Unobservable Inputs September 30, 2018 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 18.5 $ 0.9 Discounted Cash Flow Forward Market Price $ (9.40 ) $ 10.30 $ (1.49 ) Significant Unobservable Inputs December 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 6.4 $ 0.2 Discounted Cash Flow Forward Market Price $ (6.62 ) $ 1.41 $ (0.76 ) Significant Unobservable Inputs September 30, 2018 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 2.8 Discounted Cash Flow Forward Market Price (c) $ 2.19 $ 2.97 $ 2.45 FTRs 7.9 1.6 Discounted Cash Flow Forward Market Price (a) (9.40 ) 10.30 (1.49 ) Total $ 7.9 $ 4.4 Significant Unobservable Inputs December 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ — $ 0.2 Discounted Cash Flow Forward Market Price (c) $ 2.37 $ 2.96 $ 2.62 FTRs 6.7 0.6 Discounted Cash Flow Forward Market Price (a) (6.62 ) 1.41 (0.76 ) Total $ 6.7 $ 0.8 (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents market prices in dollars per MMBtu.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2018
Status of Tax Reform Regulatory Proceedings	Registrant (Jurisdiction) Change in Tax Rate Excess ADIT Subject to Normalization Requirements Excess ADIT Not Subject to Normalization Requirements AEP Texas (Texas-Distribution) Order Issued Order Issued Order Issued – Partial (a) AEP Texas (Texas-Transmission) Order Issued To be addressed in a later filing To be addressed in a later filing APCo (Virginia) Legislation Enacted – Case Pending (b) Legislation Enacted – Case Pending (b) Order Issued – Partial; Separate Case Pending (c) APCo (West Virginia) Order Issued Order Issued Order Issued I&M (Indiana) Order Issued Order Issued Order Issued I&M (Michigan) Order Issued; Separate Case Pending (d) Case Pending Case Pending AEP (Tennessee) Case Pending Case Pending Case Pending AEP (Kentucky) Order Issued Order Issued Order Issued OPCo (Ohio) Order Issued Order Issued Order Issued PSO (Oklahoma) Order Issued Order Issued Order Issued SWEPCo (Arkansas) Order Issued Order Issued Order Issued SWEPCo (Louisiana) Case Pending – Rates Implemented (e) Case Pending – Rates Implemented (e) Case Pending – Rates Implemented (e) SWEPCo (Texas) Order Issued (f) To be addressed in a later filing To be addressed in a later filing PJM FERC Transmission Settlement Approved (g) Settlement Approved (g) Settlement Approved (g) SPP FERC Transmission To be addressed in a later filing To be addressed in a later filing To be addressed in a later filing (a) A portion of the Excess ADIT that is not subject to rate normalization requirements is to be addressed in a later filing. (b) Legislation has been issued for a blanket amount that is subject to true-up and final commission approval. (c) In October 2018, the Virginia SCC issued an order approving APCo’s request to refund a portion of the Excess ADIT that is not subject to rate normalization requirements to customers. The remainder is to be addressed in a separate pending case. (d) A rider was implemented to refund the impact of Tax Reform prospectively and effective September 1, 2018. A separate filing was submitted in October 2018 for the Tax Reform impact from January 1, 2018 through August 31, 2018. (e) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval. (f) An interim order has been issued to lower rates. Parties continue to finalize settlement. (g) An administrative law judge has approved a settlement. The settlement is subject to final FERC ruling.
Estimated Provisions for Revenue Refund Related to Reduction in Corporate Federal Income Tax Rate	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Included in Current Liabilities $ 51.1 $ — $ — $ 40.5 $ 2.0 $ — $ 2.4 $ 5.3 Included in Deferred Credits and Other Noncurrent Liabilities 98.4 21.9 8.6 3.7 12.8 20.8 2.3 27.6
Estimated Provisions for Revenue Refund Offsetting Amortization of Excess ADIT	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Included in Current Liabilities $ 15.3 $ — $ — $ 9.5 $ — $ — $ 4.7 $ 1.2 Included in Deferred Credits and Other Noncurrent Liabilities 20.6 6.9 0.1 0.7 1.4 3.3 — 7.8
Schedule of Effective Income Tax Rate Reconciliation	Three Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 AEP (16.2 )% 33.0 % 5.6 % 35.3 % AEP Texas 12.6 % 32.2 % 14.9 % 33.6 % AEPTCo (a) 18.4 % 33.5 % 20.7 % 33.8 % APCo (962.2 )% 33.4 % (13.8 )% 35.5 % I&M 15.9 % 30.6 % 10.4 % 30.1 % OPCo (46.4 )% 36.9 % 4.6 % 35.6 % PSO 5.6 % 37.2 % 8.7 % 37.4 % SWEPCo 9.8 % 21.2 % 11.4 % 25.7 % (a) The 2017 ETRs presented above reflect the revisions made to AEPTCo's previously issued financial statements. See Note 1 - Significant Accounting Matters for additional information.

Financing Activities (Tables)

Financing Activities (Tables)	9 Months Ended
	Sep. 30, 2018
Long-term Debt	Type of Debt September 30, 2018 December 31, 2017 (in millions) Senior Unsecured Notes $ 18,342.1 $ 16,478.3 Pollution Control Bonds 1,643.2 1,621.7 Notes Payable 233.2 260.8 Securitization Bonds 1,145.2 1,416.5 Spent Nuclear Fuel Obligation (a) 272.1 268.6 Other Long-term Debt 1,138.2 1,127.4 Total Long-term Debt Outstanding 22,774.0 21,173.3 Long-term Debt Due Within One Year 1,904.2 1,753.7 Long-term Debt $ 20,869.8 $ 19,419.6 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $316 million and $312 million as of September 30, 2018 and December 31, 2017 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEP Texas Senior Unsecured Notes $ 500.0 3.95 2028 AEPTCo Senior Unsecured Notes 325.0 4.25 2048 APCo Pollution Control Bonds 104.4 2.625 2022 I&M Other Long-term Debt 200.0 Variable 2021 I&M Notes Payable 55.5 Variable 2022 I&M Pollution Control Bonds 100.0 3.05 2025 I&M Senior Unsecured Notes 350.0 3.85 2028 I&M Senior Unsecured Notes 475.0 4.25 2048 OPCo Senior Unsecured Notes 400.0 4.15 2048 SWEPCo Senior Unsecured Notes 575.0 4.10 2028 SWEPCo Senior Unsecured Notes 450.0 3.85 2048 Non-Registrant: Transource Energy Other Long-term Debt 12.7 Variable 2020 WPCo Pollution Control Bonds 65.0 3.00 2022 Total Issuances $ 3,612.6 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) AEP Texas Securitization Bonds $ 70.0 5.17 2018 AEP Texas Senior Unsecured Notes 30.0 5.89 2018 AEP Texas Securitization Bonds 27.6 1.976 2020 AEP Texas Securitization Bonds 104.1 5.306 2020 APCo Securitization Bonds 24.0 2.008 2023 I&M Other Long-term Debt 200.0 Variable 2018 I&M Pollution Control Bonds 100.0 1.75 2018 I&M Senior Unsecured Notes 475.0 7.00 2019 I&M Notes Payable 3.5 Variable 2019 I&M Notes Payable 10.1 Variable 2019 I&M Notes Payable 18.8 Variable 2020 I&M Notes Payable 19.5 Variable 2021 I&M Notes Payable 21.3 Variable 2022 I&M Notes Payable 6.7 Variable 2022 I&M Other Long-term Debt 1.2 6.00 2025 OPCo Senior Unsecured Notes 350.0 6.05 2018 OPCo Securitization Bonds 46.9 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Pollution Control Bonds 81.7 4.95 2018 SWEPCo Senior Unsecured Notes 300.0 5.875 2018 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.2 4.28 2023 SWEPCo Notes Payable 3.2 4.58 2032 Non-Registrant: AEP Energy Notes Payable 0.1 5.75 2019 WPCo Pollution Control Bonds 65.0 Variable 2018 Total Retirements and Principal Payments $ 1,959.5
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, 2018 Limit (in millions) AEP Texas $ 390.6 $ 106.9 $ 189.9 $ 47.1 $ (77.8 ) $ 500.0 AEPTCo 371.3 232.7 237.9 28.1 232.7 795.0 (a) APCo 295.5 23.7 185.3 23.4 (75.4 ) 600.0 I&M 322.1 657.8 257.6 116.4 72.5 500.0 OPCo 270.8 225.0 169.0 189.4 (242.9 ) 500.0 PSO 193.7 30.9 119.8 10.1 (22.0 ) 300.0 SWEPCo 200.1 525.5 143.2 343.3 516.6 350.0 (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 Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Company Money Pool Money Pool September 30, 2018 (in millions) AEP Texas $ 8.4 $ 8.1 $ 8.0 SWEPCo 2.0 2.0 2.0
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, 2018 September 30, 2018 Borrowing Limit (in millions) $ 1.1 $ 104.7 $ 1.1 $ 50.0 $ 1.1 $ 45.3 $ 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, 2018 2017 Maximum Interest Rate 2.52 % 1.49 % Minimum Interest Rate 1.81 % 0.92 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed from for Funds Loaned to the Utility Money Pool for the the Utility Money Pool for the Nine Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 AEP Texas 2.25 % 1.29 % 2.29 % 1.35 % AEPTCo 2.26 % 1.36 % 2.04 % 1.04 % APCo 2.22 % 1.24 % 2.19 % 1.28 % I&M 2.16 % 1.24 % 2.06 % 1.27 % OPCo 2.18 % 1.40 % 2.47 % 0.98 % PSO 2.25 % 1.30 % 1.86 % — % SWEPCo 2.31 % 1.26 % 1.87 % 0.98 %
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool	Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017 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 2.52 % 1.83 % 2.26 % 1.49 % — % 1.27 % SWEPCo 2.52 % 1.83 % 2.26 % 1.49 % — % 1.27 %
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 2018 2.52 % 1.76 % 2.52 % 1.76 % 2.26 % 2.27 % 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 %
Short Term Debt	September 30, 2018 December 31, 2017 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (dollars in millions) AEP Securitized Debt for Receivables (b) $ 750.0 2.06 % $ 718.0 1.22 % AEP Commercial Paper 1,473.2 2.40 % 898.6 1.85 % SWEPCo Notes Payable 19.4 3.45 % 22.0 2.92 % Total Short-term Debt $ 2,242.6 $ 1,638.6 (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 2018 2017 2018 2017 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 2.27 % 1.33 % 2.06 % 1.17 % Net Uncollectible Accounts Receivable Written Off $ 9.6 $ 7.0 $ 19.0 $ 18.2
Customer Accounts Receivable Managed Portfolio	September 30, 2018 December 31, 2017 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,082.9 $ 925.5 Short-term – Securitized Debt of Receivables 750.0 718.0 Delinquent Securitized Accounts Receivable 58.2 41.1 Bad Debt Reserves Related to Securitization 29.3 28.7 Unbilled Receivables Related to Securitization 242.1 303.2
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2018 December 31, 2017 (in millions) APCo $ 122.9 $ 136.2 I&M 169.5 136.5 OPCo 413.7 367.4 PSO 163.0 115.1 SWEPCo 190.5 138.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 (in millions) APCo $ 1.8 $ 1.5 $ 5.1 $ 4.2 I&M 2.5 1.8 6.8 4.9 OPCo 7.2 6.1 18.8 16.5 PSO 2.3 2.0 6.0 5.2 SWEPCo 2.6 2.0 6.6 5.4
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2018 2017 2018 2017 (in millions) APCo $ 334.1 $ 335.5 $ 1,079.2 $ 1,029.4 I&M 498.4 409.9 1,401.7 1,218.9 OPCo 695.2 616.3 2,046.9 1,741.7 PSO 454.9 407.0 1,171.2 1,022.6 SWEPCo 512.6 455.0 1,364.6 1,200.8

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2018
Consolidated Assets And Liabilities Of Variable Interest Entities	American Electric Power Company, Inc. Variable Interest Entities September 30, 2018 Desert Sky and Trent (in millions) ASSETS Current Assets $ 89.2 Net Property, Plant and Equipment 350.8 Other Noncurrent Assets 0.4 Total Assets $ 440.4 LIABILITIES AND EQUITY Current Liabilities $ 93.4 Noncurrent Liabilities 6.1 Equity 340.9 Total Liabilities and Equity $ 440.4

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	9 Months Ended
	Sep. 30, 2018
Disaggregated Revenues from Contracts with Customers	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 618.5 336.7 — — — — 955.2 Industrial Revenues 573.2 123.9 — — — — 697.1 Other Retail Revenues 49.0 9.8 — — — — 58.8 Total Retail Revenues 2,289.4 1,082.6 — — — — 3,372.0 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 224.2 — — 115.1 — (98.5 ) 240.8 Transmission Revenues (b) 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 (c) 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 (c) 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) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $35 million . The remaining affiliated amounts are immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $147 million . The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. (d) The alternative revenue for Transmission and Distribution Utilities is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. 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 $ 1,711.0 $ — $ — $ — $ — $ 4,617.9 Commercial Revenues 1,693.9 962.6 — — — — 2,656.5 Industrial Revenues 1,655.2 366.8 — — — — 2,022.0 Other Retail Revenues 139.1 29.2 — — — — 168.3 Total Retail Revenues 6,395.1 3,069.6 — — — — 9,464.7 Wholesale and Competitive Retail Revenues: Generation Revenues (a) 686.5 — — 413.4 — (155.2 ) 944.7 Transmission Revenues (b) 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 (c) 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 (c) 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) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $87 million . The remaining affiliated amounts are immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $444 million . The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. (d) The alternative revenue for Transmission and Distribution Utilities is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. Three Months Ended September 30, 2018 AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 178.8 $ — $ 320.9 $ 207.4 $ 433.5 $ 220.8 $ 214.0 Commercial Revenues 113.7 — 155.6 139.5 222.9 122.2 142.6 Industrial Revenues 27.2 — 157.1 148.7 96.3 80.2 87.5 Other Retail Revenues 6.5 — 19.2 1.7 3.3 24.4 2.2 Total Retail Revenues 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) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $146 million . The remaining affiliated amounts are immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial. (e) The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. (f) Amounts include affiliated and nonaffiliated revenues. Nine Months Ended September 30, 2018 AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 453.6 $ — $ 1,017.2 $ 559.4 $ 1,258.4 $ 531.4 $ 512.3 Commercial Revenues 328.5 — 443.8 373.7 632.8 317.9 378.6 Industrial Revenues 79.7 — 455.9 424.1 287.8 220.4 248.1 Other Retail Revenues 19.1 — 57.6 5.4 9.8 64.9 6.4 Total Retail Revenues 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) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $448 million . The remaining affiliated amounts are immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial. (e) The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information. (f) Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations	Company 2018 2019-2020 2021-2022 After 2022 Total (in millions) AEP $ 246.1 $ 258.7 $ 164.8 $ 349.0 $ 1,018.6 AEP Texas 74.2 — — — 74.2 AEPTCo 166.8 — — — 166.8 APCo 30.7 32.9 25.5 11.6 100.7 I&M 6.3 3.0 2.9 1.4 13.6 OPCo 21.5 12.4 — — 33.9 PSO 4.5 — — — 4.5 SWEPCo 9.1 — — — 9.1
Affiliated Accounts Receivable Contracts with Customers	Company September 30, 2018 January 1, 2018 (in millions) AEPTCo $ 71.9 $ 47.1 APCo 54.1 35.6 I&M 24.7 15.1 OPCo 42.5 26.1 PSO 17.1 6.1 SWEPCo 20.3 11.0

Significant Accounting Matter_3

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended				9 Months Ended				63 Months Ended	81 Months Ended	90 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2018		Sep. 30, 2017		Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2018	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Amounts Attributable to AEP Common Shareholders
Net Income Attributable to Noncontrolling Interests		$ 2.1		$ 12		$ 6.1		$ 15.2
Net Income (Loss) Available to Common Stockholders, Basic		$ 577.6		$ 544.7		$ 1,560.4		$ 1,511.9
Weighted Average Number of Basic AEP Common Shares Outstanding		492,984,741		491,840,722		492,649,456		491,781,643
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations		$ 1.17		$ 1.11		$ 3.17		$ 3.07
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding		493,940,543		492,986,307		493,526,937		492,428,586
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations		$ 1.17		$ 1.10		$ 3.16		$ 3.07
Antidilutive Shares Outstanding						0		0
Income (Loss) from Equity Method Investments Adjustment						$ 6
Net Income (Loss)		$ 579.7		$ 556.7		1,566.5		$ 1,527.1
Retained Earnings (Accumulated Deficit)													$ 9,293.7	$ 8,626.7
Revenues
TOTAL REVENUES		4,333.1		4,104.7		12,394.6		11,614.5
Expenses
Depreciation and Amortization		602.6		518.5		1,695.5		1,485.9
TOTAL EXPENSES		3,664.5		3,129.6		10,263		8,820.4
OPERATING INCOME (LOSS)		668.6		975.1		2,131.6		2,794.1
Other Income (Expense):
Allowance for Equity Funds Used During Construction		30.9		20		92.4		62.2
Interest Expense		(256.8)		(223.3)		(733.1)		(668)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		480.9		800.6		1,604.7		2,261.8
Income Tax Expense (Credit)		(80.7)		264		93.5		797.8
Net Income (Loss)		579.7		556.7		1,566.5		1,527.1
Accounts Receivable:
Customers													757.9	643.9
Total Accounts Receivable													2,118.1	1,891
TOTAL CURRENT ASSETS													4,692.4	4,253.1
Property, Plant and Equipment
Transmission													20,113.7	18,972.5
Other Property, Plant and Equipment													3,996.9	3,706.3
Construction Work in Progress													4,995.5	4,120.7
Total Property, Plant and Equipment													71,197.3	67,428.5
Accumulated Depreciation and Amortization													17,841.6	17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													53,355.7	50,261.5
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													9,569.3	10,214.5
TOTAL ASSETS													67,617.4	64,729.1
Liabilities, Current [Abstract]
Accounts Payable													1,579.9	2,065.3
Accrued Taxes													774.1	1,115.5
TOTAL CURRENT LIABILITIES													8,426.2	8,271.3
Noncurrent Liabilities
Deferred Income Taxes													7,110.4	6,813.9
Regulatory Liabilities and Deferred Investment Tax Credits													8,643.5	8,422.3
TOTAL NONCURRENT LIABILITIES													40,043.9	38,132.3
TOTAL LIABILITIES													48,470.1	46,403.6
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													67,617.4	64,729.1
Operating Activities
Net Income (Loss)		579.7		556.7		1,566.5		1,527.1
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		602.6		518.5		1,695.5		1,485.9
Deferred Income Taxes						43		740.9
Allowance for Equity Funds Used During Construction		(30.9)		(20)		(92.4)		(62.2)
Property Taxes						304.8		291.4
Change in Other Noncurrent Assets						161.6		(334.6)
Change in Other Noncurrent Liabilities						141.9		205.7
Accounts Receivable, Net						(52.3)		201.3
Fuel, Materials and Supplies						98.7		58.5
Accounts Payable						(45)		(91)
Accrued Taxes, Net						(247.5)		(310.1)
Other Current Assets						11.7		(98.2)
Other Current Liabilities						101.1		(260.3)
Net Cash Flows from (Used for) Operating Activities						3,932.6		3,124.2
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(4,688.7)		(1,722.7)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						1,281		(1,314.2)
Cash and Cash Equivalents at Beginning of Period						214.6
Cash and Cash Equivalents at End of Period		788.3				788.3
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						631.3		613.8
Net Cash Paid (Received) for Income Taxes						(27.9)		(6.8)
Construction Expenditures Included in Current Liabilities as of September 30,						882.3		791.6
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		788.3				214.6							788.3	214.6
Restricted Cash													149.2	198
Total Cash, Cash Equivalents and Restricted Cash													937.5	412.6
Total Cash, Cash Equivalents and Restricted Cash													937.5	412.6	$ 490.8	$ 403.5
AEP Texas Inc. [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)		57.8		64.3		151.1		146.6
Retained Earnings (Accumulated Deficit)													1,277.5	1,124.6
Revenues
TOTAL REVENUES		433.4		431.2		1,193.3		1,164.3
Expenses
Depreciation and Amortization		133.3		124		364.9		343
TOTAL EXPENSES		339.4		302.4		931.3		844.4
OPERATING INCOME (LOSS)		94		128.8		262		319.9
Other Income (Expense):
Allowance for Equity Funds Used During Construction		5.8		0		15.2		2.2
Interest Expense		(37.3)		(35.3)		(108.9)		(105.6)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		66.1		94.9		177.5		220.8
Income Tax Expense (Credit)		8.3		30.6		26.4		74.2
Net Income (Loss)		57.8		64.3		151.1		146.6
Accounts Receivable:
Customers													132.9	105.3
Total Accounts Receivable													220.5	194
Accrued Tax Benefits													14.6	41
TOTAL CURRENT ASSETS													437.9	563.8
Property, Plant and Equipment
Transmission													3,302.3	3,053.6
Other Property, Plant and Equipment													554	461
Construction Work in Progress													1,108.8	835.7
Total Property, Plant and Equipment													9,285.6	8,419.6
Accumulated Depreciation and Amortization													1,643.9	1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													7,641.7	6,825.1
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													1,212.1	1,384.7
TOTAL ASSETS													9,291.7	8,773.6
Liabilities, Current [Abstract]
Accounts Payable													208.8	379.4
Affiliated Companies													31.7	30.2
Accrued Taxes													90.8	77.2
TOTAL CURRENT LIABILITIES													1,086.2	871.5
Noncurrent Liabilities
Deferred Income Taxes													902.3	913.1
Regulatory Liabilities and Deferred Investment Tax Credits													1,346.4	1,320.5
TOTAL NONCURRENT LIABILITIES													5,784.5	5,732.2
TOTAL LIABILITIES													6,870.7	6,603.7
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													9,291.7	8,773.6
Operating Activities
Net Income (Loss)		57.8		64.3		151.1		146.6
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		133.3		124		364.9		343
Deferred Income Taxes						(21.2)		124.1
Allowance for Equity Funds Used During Construction		(5.8)		0		(15.2)		(2.2)
Property Taxes						(19.2)		(15.9)
Change in Other Noncurrent Assets						(14.2)		(29.1)
Change in Other Noncurrent Liabilities						67.1		7.4
Accounts Receivable, Net						(26.5)		(47.6)
Fuel, Materials and Supplies						(2.4)		(0.1)
Accounts Payable						(19.1)		77.3
Accrued Taxes, Net						40		1.7
Other Current Assets						(6.3)		(2.5)
Other Current Liabilities						14.1		(31.2)
Net Cash Flows from (Used for) Operating Activities						490.8		490.5
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(961.1)		(1,043)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						437.4		528.7
Cash and Cash Equivalents at Beginning of Period						2
Cash and Cash Equivalents at End of Period		0.1				0.1
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						92.2		101.1
Net Cash Paid (Received) for Income Taxes						(14.2)		(23.3)
Construction Expenditures Included in Current Liabilities as of September 30,						176.4		166.1
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		0.1				2							0.1	2
Restricted Cash													124.2	155.2
Total Cash, Cash Equivalents and Restricted Cash													124.3	157.2
Total Cash, Cash Equivalents and Restricted Cash													124.3	157.2	123.1	146.9
AEP Transmission Co [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)		78.1		58.6	[1]	244.2	[1]	212.4	[1]
Retained Earnings (Accumulated Deficit)													1,017.5	773.3
Revenues
TOTAL REVENUES		194.4	[2]	165.6	[1]	586.2	[1],[2]	534.8	[1]
Expenses
Depreciation and Amortization		34.9		24.6		97.5		69.7
TOTAL EXPENSES		97.4		72		267.6		197.3
OPERATING INCOME (LOSS)		97		93.6		318.6		337.5
Other Income (Expense):
Allowance for Equity Funds Used During Construction		18		11.4		48.7		33
Interest Expense		(19.8)		(17.1)	[1]	(60.7)	[1]	(50.4)	[1]
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		95.7		88.1		307.9		320.6
Income Tax Expense (Credit)		17.6		29.5	[1]	63.7	[1]	108.2	[1]
Net Income (Loss)		78.1		58.6	[1]	244.2	[1]	212.4	[1]
Accounts Receivable:
Customers													11.9	15
Total Accounts Receivable													86	109.5
Accrued Tax Benefits													29.8	49.4
TOTAL CURRENT ASSETS													413.7	326.4
Property, Plant and Equipment
Transmission													5,833.5	5,319.7
Other Property, Plant and Equipment													155.2	126.8
Construction Work in Progress													1,772.9	1,324
Total Property, Plant and Equipment	[1]												7,761.6	6,770.5
Accumulated Depreciation and Amortization	[1]												234.6	152.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]												7,527	6,617.9
Other Noncurrent Assets
Deferred Property Taxes													38.1	125
TOTAL OTHER NONCURRENT ASSETS													57.7	137.8
TOTAL ASSETS	[1]												7,998.4	7,082.1
Liabilities, Current [Abstract]
Accounts Payable													237.4	484.5
Affiliated Companies													79	66.1
Accrued Taxes													138.7	231.5
TOTAL CURRENT LIABILITIES													546.4	866.9
Noncurrent Liabilities
Deferred Income Taxes													684.4	600.4
Regulatory Liabilities and Deferred Investment Tax Credits													509.6	493.8
TOTAL NONCURRENT LIABILITIES													4,035.9	3,625.3
TOTAL LIABILITIES													4,582.3	4,492.2
Equity [Abstract]
TOTAL MEMBER'S EQUITY													3,416.1	2,589.9	2,355.5	1,957.6
TOTAL LIABILITIES AND EQUITY													7,998.4	7,082.1
Operating Activities
Net Income (Loss)		78.1		58.6	[1]	244.2	[1]	212.4	[1]
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		34.9		24.6		97.5		69.7
Deferred Income Taxes						76.3		191.9
Allowance for Equity Funds Used During Construction		(18)		(11.4)		(48.7)		(33)
Property Taxes						86.9		72.4
Long-term Accounts Receivable - Affiliated						(3.1)		(13.8)
Change in Other Noncurrent Assets						12.7		8.6
Change in Other Noncurrent Liabilities						18		25.7
Accounts Receivable, Net						23.5		(40.8)
Fuel, Materials and Supplies						(2.8)		(11)
Accounts Payable						3.3		20.4
Accrued Taxes, Net						(73.2)		(71.2)
Accrued Interest						20.9		18.4
Other Current Assets						(0.5)		(5.3)
Other Current Liabilities						(28)		0.5
Net Cash Flows from (Used for) Operating Activities						427		444.9
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(1,315.5)		(1,277.4)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						888.5		832.5
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		0		0			$ 0
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						38.4		30.4
Net Cash Paid (Received) for Income Taxes						(32.1)		(93.4)
Construction Expenditures Included in Current Liabilities as of September 30,						237		248.9
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		0		0		0		0			0		0	0	0	0
Appalachian Power Co [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)		87.1		86		290		248.7
Retained Earnings (Accumulated Deficit)													1,884.2	1,714.1
Revenues
TOTAL REVENUES		762		719.3		2,249.4		2,187.4
Expenses
Depreciation and Amortization		105.7		102.8		319.5		304.1
TOTAL EXPENSES		712.2		547.6		1,874		1,670.7
OPERATING INCOME (LOSS)		49.8		171.7		375.4		516.7
Other Income (Expense):
Allowance for Equity Funds Used During Construction		4.1		2.7		9.6		6.2
Interest Expense		(50.8)		(47.2)		(146)		(143.5)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		8.2		129.2		254.9		385.4
Income Tax Expense (Credit)		(78.9)		43.2		(35.1)		136.7
Net Income (Loss)		87.1		86		290		248.7
Accounts Receivable:
Customers													155.7	123.1
Total Accounts Receivable													275.8	263.9
TOTAL CURRENT ASSETS													630.9	636.2
Property, Plant and Equipment
Transmission													3,141.2	3,019.9
Other Property, Plant and Equipment													461.4	427.9
Construction Work in Progress													602.1	483
Total Property, Plant and Equipment													14,591.9	14,141.5
Accumulated Depreciation and Amortization													4,086.2	3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													10,505.7	10,245.1
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													921.3	1,047.3
TOTAL ASSETS													12,057.9	11,928.6
Liabilities, Current [Abstract]
Accounts Payable													219.1	264.9
Affiliated Companies													73.6	92.7
Accrued Taxes													81.5	94.5
TOTAL CURRENT LIABILITIES													1,216.5	1,124.2
Noncurrent Liabilities
Deferred Income Taxes													1,581.5	1,565.7
Regulatory Liabilities and Deferred Investment Tax Credits													1,423.8	1,454.9
TOTAL NONCURRENT LIABILITIES													6,869.5	6,999.9
TOTAL LIABILITIES													8,086	8,124.1
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													12,057.9	11,928.6
Operating Activities
Net Income (Loss)		87.1		86		290		248.7
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		105.7		102.8		319.5		304.1
Deferred Income Taxes						(83.8)		121.7
Allowance for Equity Funds Used During Construction		(4.1)		(2.7)		(9.6)		(6.2)
Change in Other Noncurrent Assets						94.8		37.1
Change in Other Noncurrent Liabilities						3.8		7.9
Accounts Receivable, Net						39.4		39.9
Fuel, Materials and Supplies						53		14
Accounts Payable						(21.5)		6.2
Accrued Taxes, Net						(20.2)		(44.2)
Other Current Assets						(7.9)		(2.5)
Other Current Liabilities						64.1		9.1
Net Cash Flows from (Used for) Operating Activities						690.7		702.2
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(565.4)		(547.7)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						(132.4)		(161.8)
Cash and Cash Equivalents at Beginning of Period						2.9
Cash and Cash Equivalents at End of Period		2.2				2.2
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						104.5		107.1
Net Cash Paid (Received) for Income Taxes						26.7		24.4
Construction Expenditures Included in Current Liabilities as of September 30,						87.6		107.2
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		2.2				2.9							2.2	2.9
Restricted Cash													9.9	16.3
Total Cash, Cash Equivalents and Restricted Cash													12.1	19.2	11.2	18.5
Indiana Michigan Power Co [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)		72.7		64.9		231.6		143.8
Retained Earnings (Accumulated Deficit)													1,318.6	1,192.2
Revenues
TOTAL REVENUES		629.7		557.7		1,796.2		1,585.5
Expenses
Depreciation and Amortization		85.2		55		207.1		154.8
TOTAL EXPENSES		519.5		444.1		1,471.2		1,321.1
OPERATING INCOME (LOSS)		110.2		113.6		325		264.4
Other Income (Expense):
Allowance for Equity Funds Used During Construction		3.9		3.5		8		8.1
Interest Expense		(34.5)		(27.5)		(95.6)		(83)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		86.4		93.5		258.4		205.6
Income Tax Expense (Credit)		13.7		28.6		26.8		61.8
Net Income (Loss)		72.7		64.9		231.6		143.8
Accounts Receivable:
Customers													70.5	56.4
Total Accounts Receivable													140	115.6
Accrued Tax Benefits													35.4	58.4
TOTAL CURRENT ASSETS													483.7	434
Property, Plant and Equipment
Transmission													1,543.3	1,504
Other Property, Plant and Equipment													584.7	595.2
Construction Work in Progress													458.6	460.2
Total Property, Plant and Equipment													9,350.4	9,074.6
Accumulated Depreciation and Amortization													3,113.9	3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													6,236.5	6,050.4
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													3,387.9	3,287.6
TOTAL ASSETS													10,108.1	9,772
Liabilities, Current [Abstract]
Accounts Payable													142.6	154.5
Affiliated Companies													65.6	98.3
Accrued Taxes													44.7	81.3
TOTAL CURRENT LIABILITIES													621	1,211.3
Noncurrent Liabilities
Deferred Income Taxes													1,010	953.8
Regulatory Liabilities and Deferred Investment Tax Credits													1,791.9	1,708.7
TOTAL NONCURRENT LIABILITIES													7,144.6	6,343.1
TOTAL LIABILITIES													7,765.6	7,554.4
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													10,108.1	9,772
Operating Activities
Net Income (Loss)		72.7		64.9		231.6		143.8
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		85.2		55		207.1		154.8
Deferred Income Taxes						28.1		132.2
Allowance for Equity Funds Used During Construction		(3.9)		(3.5)		(8)		(8.1)
Change in Other Noncurrent Assets						(7.4)		(32.2)
Change in Other Noncurrent Liabilities						46.3		40.9
Accounts Receivable, Net						6.5		19.3
Fuel, Materials and Supplies						(1.1)		(4.1)
Accounts Payable						(34.7)		16.6
Accrued Taxes, Net						(7.1)		(30.2)
Accrued Interest						(15.3)		(17.4)
Other Current Assets						4.9		8
Other Current Liabilities						0.3		(14.2)
Net Cash Flows from (Used for) Operating Activities						571.3		524.3
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(549.6)		(568.8)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						(21.4)		44.6
Net Increase (Decrease) in Cash and Cash Equivalents						0.3		0.1
Cash and Cash Equivalents at Beginning of Period						1.3		1.2
Cash and Cash Equivalents at End of Period		1.6		1.3		1.6		1.3			1.3
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						104.4		92
Net Cash Paid (Received) for Income Taxes						(26.5)		(69.6)
Construction Expenditures Included in Current Liabilities as of September 30,						66.4		74.5
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		1.6		1.3		1.3		1.2			1.3		1.6	1.3	1.3	1.2
Ohio Power Co [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)		88.7		82.6		237.1		231.1
Retained Earnings (Accumulated Deficit)													1,048	1,148.4
Revenues
TOTAL REVENUES		778.3		742		2,318		2,152
Expenses
Depreciation and Amortization		70.4		57.3		200.3		165.7
TOTAL EXPENSES		698.4		588.6		2,016.4		1,730.5
OPERATING INCOME (LOSS)		79.9		153.4		301.6		421.5
Other Income (Expense):
Allowance for Equity Funds Used During Construction		2		0.9		7.8		4.1
Interest Expense		(26.1)		(25.7)		(76.6)		(76.8)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		60.6		130.9		248.5		359.1
Income Tax Expense (Credit)		(28.1)		48.3		11.4		128
Net Income (Loss)		88.7		82.6		237.1		231.1
Accounts Receivable:
Customers													116.9	67.8
Total Accounts Receivable													221.5	169
TOTAL CURRENT ASSETS													353.1	397.9
Property, Plant and Equipment
Transmission													2,484.5	2,419.2
Other Property, Plant and Equipment													547.5	495.9
Construction Work in Progress													475.7	410.1
Total Property, Plant and Equipment													8,333.3	7,951.6
Accumulated Depreciation and Amortization													2,230.6	2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													6,102.7	5,766.8
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													662.8	1,097
TOTAL ASSETS													7,118.6	7,261.7
Liabilities, Current [Abstract]
Accounts Payable													169.2	205.8
Affiliated Companies													95.3	118.2
Accrued Taxes													293.8	512.5
TOTAL CURRENT LIABILITIES													1,137.8	1,593.8
Noncurrent Liabilities
Deferred Income Taxes													742.8	762.9
Regulatory Liabilities and Deferred Investment Tax Credits													1,197.7	1,100.2
TOTAL NONCURRENT LIABILITIES													3,771.5	3,357.6
TOTAL LIABILITIES													4,909.3	4,951.4
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													7,118.6	7,261.7
Operating Activities
Net Income (Loss)		88.7		82.6		237.1		231.1
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		70.4		57.3		200.3		165.7
Deferred Income Taxes						(71.9)		117.5
Allowance for Equity Funds Used During Construction		(2)		(0.9)		(7.8)		(4.1)
Property Taxes						191.1		175.9
Change in Other Noncurrent Assets						0.8		(44.5)
Change in Other Noncurrent Liabilities						62.5		43.4
Accounts Receivable, Net						21.3		14.9
Fuel, Materials and Supplies						(3.7)		(7.1)
Accounts Payable						(31.8)		(31.2)
Accrued Taxes, Net						(210.6)		(284.3)
Other Current Assets						9.1		(17.3)
Other Current Liabilities						(4.3)		(34.8)
Net Cash Flows from (Used for) Operating Activities						700.8		330.9
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(523)		(331.4)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						(188.8)		(11.1)
Cash and Cash Equivalents at Beginning of Period						3.1
Cash and Cash Equivalents at End of Period		3.5				3.5
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						67.3		68.1
Net Cash Paid (Received) for Income Taxes						54.1		69.6
Construction Expenditures Included in Current Liabilities as of September 30,						66		56.8
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		3.5				3.1							3.5	3.1
Restricted Cash													15.2	26.6
Total Cash, Cash Equivalents and Restricted Cash													18.7	29.7	18.7	30.3
Public Service Co Of Oklahoma [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)		60.4		46.2		89.8		71.4
Retained Earnings (Accumulated Deficit)													743.8	691.5
Revenues
TOTAL REVENUES		481.4		442.8		1,216.5		1,091.6
Expenses
Depreciation and Amortization		42.3		31.7		120.5		97.8
TOTAL EXPENSES		402.9		356.9		1,076.9		940.5
OPERATING INCOME (LOSS)		78.5		85.9		139.6		151.1
Other Income (Expense):
Allowance for Equity Funds Used During Construction						(0.3)		0.4
Interest Expense		(16.4)		(13.2)		(47.4)		(40.2)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		64		73.6		98.4		114
Income Tax Expense (Credit)		3.6		27.4		8.6		42.6
Net Income (Loss)		60.4		46.2		89.8		71.4
Accounts Receivable:
Customers													28.8	32.5
Total Accounts Receivable													72.8	69.4
Accrued Tax Benefits													12.5	28.1
TOTAL CURRENT ASSETS													169.8	205.3
Property, Plant and Equipment
Transmission													881.5	858.8
Other Property, Plant and Equipment													308.3	287.4
Construction Work in Progress													85.7	111.3
Total Property, Plant and Equipment													5,394.9	5,279.8
Accumulated Depreciation and Amortization													1,461.2	1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													3,933.7	3,886.2
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													410	416.8
TOTAL ASSETS													4,513.5	4,508.3
Liabilities, Current [Abstract]
Accounts Payable													113	102.4
Affiliated Companies													42.2	48
Accrued Taxes													40.5	22.6
TOTAL CURRENT LIABILITIES													386.3	436
Noncurrent Liabilities
Deferred Income Taxes													636.6	642
Regulatory Liabilities and Deferred Investment Tax Credits													850.3	853.5
TOTAL NONCURRENT LIABILITIES													2,859.8	2,857
TOTAL LIABILITIES													3,246.1	3,293
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													4,513.5	4,508.3
Operating Activities
Net Income (Loss)		60.4		46.2		89.8		71.4
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		42.3		31.7		120.5		97.8
Deferred Income Taxes						(13.4)		93.7
Allowance for Equity Funds Used During Construction						0.3		(0.4)
Property Taxes						(9.6)		(9.4)
Change in Other Noncurrent Assets						6.9		(19.8)
Change in Other Noncurrent Liabilities						10.9		(1.4)
Accounts Receivable, Net						(3.4)		5.8
Fuel, Materials and Supplies						(1.5)		13.5
Accounts Payable						6.9		(18.5)
Accrued Taxes, Net						38.4		20.1
Other Current Assets						0.3		(8.2)
Other Current Liabilities						15.1		1.5
Net Cash Flows from (Used for) Operating Activities						326.7		191.9
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(158.9)		(201.6)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						(167.5)		10.3
Net Increase (Decrease) in Cash and Cash Equivalents						0.3		0.6
Cash and Cash Equivalents at Beginning of Period						1.6		1.5
Cash and Cash Equivalents at End of Period		1.9		2.1		1.9		2.1			2.1
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						42		40.9
Net Cash Paid (Received) for Income Taxes						1.6		(46.6)
Construction Expenditures Included in Current Liabilities as of September 30,						24.3		15.1
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		1.9		2.1		1.6		1.5			2.1		1.9	1.6	2.1	1.5
Southwestern Electric Power Co [Member]
Amounts Attributable to AEP Common Shareholders
Net Income Attributable to Noncontrolling Interests		1.4		11		4.1		12.6
Net Income (Loss) Available to Common Stockholders, Basic		88.2		73.1		137.6		113.9
Weighted Average Dilutive Effect of:
Income (Loss) from Equity Method Investments Adjustment						6.3
Net Income (Loss)		89.6		84.1		141.7		126.5
Retained Earnings (Accumulated Deficit)													1,503.8	1,426.6
Revenues
TOTAL REVENUES		535.3		517.6		1,411.8		1,343.6
Expenses
Depreciation and Amortization		59.9		55.2		175.9		158.1
TOTAL EXPENSES		408.2		381.6		1,172.6		1,080.7
OPERATING INCOME (LOSS)		127.1		136		239.2		262.9
Other Income (Expense):
Allowance for Equity Funds Used During Construction		0.6		0.4		3.8		1.2
Interest Expense		(32.7)		(31.9)		(95.8)		(92.7)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		98.4		106.2		157.6		176.2
Income Tax Expense (Credit)		9.6		22.5		17.9		45.2
Net Income (Loss)		89.6		84.1		141.7		126.5
Accounts Receivable:
Customers													29.1	70.9
Total Accounts Receivable													81.9	125.6
TOTAL CURRENT ASSETS													842.5	380.4
Property, Plant and Equipment
Transmission													1,812	1,679.8
Other Property, Plant and Equipment													744.4	684.1
Construction Work in Progress													234.5	233.2
Total Property, Plant and Equipment													9,592.9	9,317.8
Accumulated Depreciation and Amortization													2,798.9	2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET													6,794	6,632
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS													350.9	330.5
TOTAL ASSETS													7,987.4	7,342.9
Liabilities, Current [Abstract]
Accounts Payable													117.6	160.4
Affiliated Companies													41.3	63.7
Accrued Taxes													75.2	39
TOTAL CURRENT LIABILITIES													913.5	598.6
Noncurrent Liabilities
Deferred Income Taxes													932.9	917.7
Regulatory Liabilities and Deferred Investment Tax Credits													896.7	896.4
TOTAL NONCURRENT LIABILITIES													4,759.6	4,509.8
TOTAL LIABILITIES													5,673.1	5,108.4
Equity [Abstract]
TOTAL LIABILITIES AND EQUITY													7,987.4	7,342.9
Operating Activities
Net Income (Loss)		89.6		84.1		141.7		126.5
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization		59.9		55.2		175.9		158.1
Deferred Income Taxes						2		79.8
Allowance for Equity Funds Used During Construction		(0.6)		(0.4)		(3.8)		(1.2)
Property Taxes						(15.8)		(15.4)
Change in Other Noncurrent Assets						(8.9)		(2.9)
Change in Other Noncurrent Liabilities						52.1		(5.2)
Accounts Receivable, Net						44.3		12.1
Fuel, Materials and Supplies						5		13.6
Accounts Payable						(29.9)		(25.7)
Accrued Taxes, Net						38.4		69.1
Accrued Interest						(11.4)		(20)
Other Current Assets						3.2		0.7
Other Current Liabilities						15.6		(14.6)
Net Cash Flows from (Used for) Operating Activities						415.3		355.9
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities						(852)		(94.4)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities						437.6		(269.6)
Net Increase (Decrease) in Cash and Cash Equivalents						0.9		(8.1)
Cash and Cash Equivalents at Beginning of Period						1.6		10.3
Cash and Cash Equivalents at End of Period		2.5		2.2		2.5		2.2			2.2
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts						102.5		109.4
Net Cash Paid (Received) for Income Taxes						12.9		(70.5)
Construction Expenditures Included in Current Liabilities as of September 30,						37		40.7
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents		$ 2.5		$ 2.2		$ 1.6		$ 10.3			2.2		$ 2.5	1.6	2.2	10.3
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares		900,000		1,200,000		900,000		600,000
Dilutive Securities, Effect on Basic Earnings Per Share		$ 0		$ (0.01)		$ (0.01)		$ 0
Previously Reported [Member] | AEP Transmission Co [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)				$ 59.9				$ 224.3
Retained Earnings (Accumulated Deficit)														788.7
Revenues
TOTAL REVENUES				167.3				549.4
Expenses
Depreciation and Amortization				24.8				70.9
TOTAL EXPENSES				72.2				198.5
OPERATING INCOME (LOSS)				95.1				350.9
Other Income (Expense):
Allowance for Equity Funds Used During Construction				11.7				36
Interest Expense				(16.9)				(48.6)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS				90.1				338.8
Income Tax Expense (Credit)				30.2				114.5
Net Income (Loss)				59.9				224.3
Accounts Receivable:
Customers														19.1
Total Accounts Receivable														113.6
Accrued Tax Benefits														46.6
TOTAL CURRENT ASSETS														327.7
Property, Plant and Equipment
Transmission														5,336.1
Other Property, Plant and Equipment														131.4
Construction Work in Progress														1,312.7
Total Property, Plant and Equipment														6,780.2
Accumulated Depreciation and Amortization														170.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET														6,609.8
Other Noncurrent Assets
Deferred Property Taxes														117.8
TOTAL OTHER NONCURRENT ASSETS														130.6
TOTAL ASSETS														7,068.1
Liabilities, Current [Abstract]
Accounts Payable														473.2
Affiliated Companies														52.9
Accrued Taxes														225.4
TOTAL CURRENT LIABILITIES														836.3
Noncurrent Liabilities
Deferred Income Taxes														601.7
Regulatory Liabilities and Deferred Investment Tax Credits														493.7
TOTAL NONCURRENT LIABILITIES														3,626.5
TOTAL LIABILITIES														4,462.8
Equity [Abstract]
TOTAL MEMBER'S EQUITY														2,605.3
TOTAL LIABILITIES AND EQUITY														7,068.1
Operating Activities
Net Income (Loss)				59.9				224.3
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization				24.8				70.9
Deferred Income Taxes								193
Allowance for Equity Funds Used During Construction				(11.7)				(36)
Change in Other Noncurrent Assets								7.6
Accounts Receivable, Net								(44.4)
Accounts Payable								8.6
Accrued Taxes, Net								(66)
Net Cash Flows from (Used for) Operating Activities								444.9
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities								(1,277.4)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities								832.5
Net Increase (Decrease) in Cash and Cash Equivalents								0
Cash and Cash Equivalents at Beginning of Period								0
Cash and Cash Equivalents at End of Period				0				0			0
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts								28.6
Construction Expenditures Included in Current Liabilities as of September 30,								239
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents				0				0			$ 0				0	0
Revision [Member] | AEP Transmission Co [Member]
Weighted Average Dilutive Effect of:
Net Income (Loss)				(1.3)				(11.9)
Retained Earnings (Accumulated Deficit)														(15.4)
Error Corrections and Prior Period Adjustments, Description										AEPTCo recorded a pretax out of period correction of an error of approximately $17 million related to revenue recorded from 2013 through March 31, 2018 in the second quarter of 2018	The $(18) million adjustment to pretax income for the nine months ended September 30, 2017 includes adjustments of $(12) million relating to 2016 and earlier periods. The effect of recording this adjustment of $(12) million in 2017 is not material to AEPTCo’s financial statements for 2017 or any earlier period.	The impact of this misstatement reduced AEPTCo’s pretax income by approximately $7 million on a cumulative basis for the period 2011 through June 30, 2018
Revenues
TOTAL REVENUES				(1.7)				(14.6)
Expenses
Depreciation and Amortization				(0.2)				(1.2)
TOTAL EXPENSES				(0.2)				(1.2)
OPERATING INCOME (LOSS)				(1.5)				(13.4)
Other Income (Expense):
Allowance for Equity Funds Used During Construction				(0.3)				(3)
Interest Expense				(0.2)				(1.8)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS				(2)				(18.2)
Income Tax Expense (Credit)				(0.7)				(6.3)
Net Income (Loss)				(1.3)				(11.9)
Accounts Receivable:
Customers														(4.1)
Total Accounts Receivable														(4.1)
Accrued Tax Benefits														2.8
TOTAL CURRENT ASSETS														(1.3)
Property, Plant and Equipment
Transmission														(16.4)
Other Property, Plant and Equipment														(4.6)
Construction Work in Progress														11.3
Total Property, Plant and Equipment														(9.7)
Accumulated Depreciation and Amortization														(17.8)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET														8.1
Other Noncurrent Assets
Deferred Property Taxes														7.2
TOTAL OTHER NONCURRENT ASSETS														7.2
TOTAL ASSETS														14
Liabilities, Current [Abstract]
Accounts Payable														11.3
Affiliated Companies														13.2
Accrued Taxes														6.1
TOTAL CURRENT LIABILITIES														30.6
Noncurrent Liabilities
Deferred Income Taxes														(1.3)
Regulatory Liabilities and Deferred Investment Tax Credits														0.1
TOTAL NONCURRENT LIABILITIES														(1.2)
TOTAL LIABILITIES														29.4
Equity [Abstract]
TOTAL MEMBER'S EQUITY														(15.4)
TOTAL LIABILITIES AND EQUITY														$ 14
Operating Activities
Net Income (Loss)				(1.3)				(11.9)
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation and Amortization				(0.2)				(1.2)
Deferred Income Taxes								(1.1)
Allowance for Equity Funds Used During Construction				0.3				3
Change in Other Noncurrent Assets								1
Accounts Receivable, Net								3.6
Accounts Payable								11.8
Accrued Taxes, Net								(5.2)
Net Cash Flows from (Used for) Operating Activities								0
Net Cash Provided by (Used in) Investing Activities [Abstract]
Net Cash Provided by (Used in) Investing Activities								0
Net Cash Provided by (Used in) Financing Activities [Abstract]
Net Cash Provided by (Used in) Financing Activities								0
Net Increase (Decrease) in Cash and Cash Equivalents								0
Cash and Cash Equivalents at Beginning of Period								0
Cash and Cash Equivalents at End of Period				0				0			$ 0
Supplementary Information [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts								1.8
Construction Expenditures Included in Current Liabilities as of September 30,								9.9
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and Cash Equivalents				$ 0				$ 0			$ 0				$ 0	$ 0
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[2]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		$ (94.8)	$ (161.6)	$ (67.8)	$ (156.3)
Change in Fair Value Recognized in AOCI		14.5	(16.9)	32.7	(34)
Commodity
Generation & Marketing Revenues		4,333.1	4,104.7	12,394.6	11,614.5
Interest Rate
Interest Expense		256.8	223.3	733.1	668
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		(7.3)	4.8	(27.9)	22.8
Income Tax (Expense) Credit		80.7	(264)	(93.5)	(797.8)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(5.7)	3.1	(22)	14.9
Net Current Period Other Comprehensive Income (Loss)		8.8	(13.8)	10.7	(19.1)
ASU 2018-02 Adoption				(3)
ASU 2016-01 Adoption				0
Ending Balance in AOCI		(86)	(175.4)	(86)	(175.4)
Securities Available for Sale [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI			10.2	11.9	8.4
Change in Fair Value Recognized in AOCI			0.9	0	2.7
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit			0	0	0
Reclassification from AOCI, Net of Income Tax (Expense) Credit			0	0	0
Net Current Period Other Comprehensive Income (Loss)			0.9	0	2.7
ASU 2018-02 Adoption	[1]			0
ASU 2016-01 Adoption	[1]			(11.9)
Ending Balance in AOCI		0	11.1	0	11.1
Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(49.1)	(125.4)	(38.3)	(125.9)
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) Credit		(1.8)	0.4	(5.1)	1.2
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(1.4)	0.3	(4)	0.8
Net Current Period Other Comprehensive Income (Loss)		(1.4)	0.3	(4)	0.8
ASU 2018-02 Adoption	[1]			(8.2)
ASU 2016-01 Adoption	[1]			0
Ending Balance in AOCI		(50.5)	(125.1)	(50.5)	(125.1)
Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				10.7	(19.1)
ASU 2018-02 Adoption	[1]			(17)
ASU 2016-01 Adoption	[1]			(11.9)
Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(30.4)	(36)	(28.4)	(23.1)
Change in Fair Value Recognized in AOCI		12.2	(15.8)	30.4	(39.4)
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		(5.9)	4	(23.7)	20.4
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(4.6)	2.6	(18.7)	13.3
Net Current Period Other Comprehensive Income (Loss)		7.6	(13.2)	11.7	(26.1)
ASU 2018-02 Adoption	[1]			(6.1)
ASU 2016-01 Adoption	[1]			0
Ending Balance in AOCI		(22.8)	(49.2)	(22.8)	(49.2)
Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(15.3)	(10.4)	(13)	(15.7)
Change in Fair Value Recognized in AOCI		2.3	(2)	2.3	2.7
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		0.4	0.4	0.9	1.2
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.3	0.2	0.7	0.8
Net Current Period Other Comprehensive Income (Loss)		2.6	(1.8)	3	3.5
ASU 2018-02 Adoption	[1]			(2.7)
ASU 2016-01 Adoption	[1]			0
Ending Balance in AOCI		(12.7)	(12.2)	(12.7)	(12.2)
Generation and Marketing Revenues [Member]
Commodity
Generation & Marketing Revenues		486.5	441.5	1,399.3	1,386.8
Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		784.7	718.1	2,551.7	2,156.9
Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.4	0.4	0.9	1.2
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(5)	(5)	(14.7)	(14.8)
Amortization of Actuarial (Gains)/Losses		3.2	5.4	9.6	16
Income Tax (Expense) Credit		(1.6)	1.7	(5.9)	7.9
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [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
Amortization of Actuarial (Gains)/Losses			0	0	0
Income Tax (Expense) Credit			0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0	0	0	0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(5)	(5)	(14.7)	(14.8)
Amortization of Actuarial (Gains)/Losses		3.2	5.4	9.6	16
Income Tax (Expense) Credit		(0.4)	0.1	(1.1)	0.4
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0	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) Credit		(1.3)	1.4	(5)	7.1
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.4	0.4	0.9	1.2
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) Credit		0.1	0.2	0.2	0.4
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Commodity
Generation & Marketing Revenues	[2]	(0.1)	(0.9)	(0.1)	(5.6)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Securities Available for Sale [Member]
Commodity
Generation & Marketing Revenues	[2]		0	0	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)	(0.9)	(0.1)	(5.6)
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]	(5.8)	4.9	(23.6)	26
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Securities Available for Sale [Member]
Commodity
Purchased Electricity for Resale	[2]		0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member]
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]	(5.8)	4.9	(23.6)	26
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
AEP Texas Inc. [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(14.7)	(14.3)	(12.6)	(14.9)
Change in Fair Value Recognized in AOCI		0	0	0	0
Commodity
Generation & Marketing Revenues		407.3
Interest Rate
Interest Expense		37.3	35.3	108.9	105.6
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		0.4	0.4	1.1	1.3
Income Tax (Expense) Credit		(8.3)	(30.6)	(26.4)	(74.2)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.3	0.3	0.9	0.9
Net Current Period Other Comprehensive Income (Loss)		0.3	0.3	0.9	0.9
ASU 2018-02 Adoption				(0.9)
Ending Balance in AOCI		(14.4)	(14)	(14.4)	(14)
AEP Texas Inc. [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(9.8)	(9.4)	(8.1)	(9.5)
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) Credit		0	0.1	0.1	0.3
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0	0.1	0.1	0.2
Net Current Period Other Comprehensive Income (Loss)		0	0.1	0.1	0.2
ASU 2018-02 Adoption	[1]			(1.8)
Ending Balance in AOCI		(9.8)	(9.3)	(9.8)	(9.3)
AEP Texas Inc. [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				0.9	0.9
ASU 2018-02 Adoption	[1]			(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		(4.9)	(4.9)	(4.5)	(5.4)
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) Credit		0.4	0.3	1	1
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.3	0.2	0.8	0.7
Net Current Period Other Comprehensive Income (Loss)		0.3	0.2	0.8	0.7
ASU 2018-02 Adoption	[1]			(0.9)
Ending Balance in AOCI		(4.6)	(4.7)	(4.6)	(4.7)
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.4	0.3	1	1
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0	(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains)/Losses		0	0.2	0.2	0.4
Income Tax (Expense) Credit		0.1	0.1	0.2	0.4
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0	0	0	0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0	(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains)/Losses		0	0.2	0.2	0.4
Income Tax (Expense) Credit		0	0	0	0.1
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	0.3	1	1
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) Credit		0.1	0.1	0.2	0.3
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(0.4)	(9.4)	1.3	(8.4)
Change in Fair Value Recognized in AOCI		0	0	(0.7)	0
Commodity
Generation & Marketing Revenues		764.1
Interest Rate
Interest Expense		50.8	47.2	146	143.5
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		(1.3)	(0.7)	(2.9)	(2.2)
Income Tax (Expense) Credit		78.9	(43.2)	35.1	(136.7)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(1)	(0.4)	(2.3)	(1.4)
Net Current Period Other Comprehensive Income (Loss)		(1)	(0.4)	(3)	(1.4)
ASU 2018-02 Adoption				0.4
Ending Balance in AOCI		(1.4)	(9.8)	(1.4)	(9.8)
Appalachian Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(2.7)	(11.9)	(0.9)	(11.3)
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) Credit		(0.9)	(0.5)	(2.9)	(1.4)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(0.7)	(0.3)	(2.3)	(0.9)
Net Current Period Other Comprehensive Income (Loss)		(0.7)	(0.3)	(2.3)	(0.9)
ASU 2018-02 Adoption	[1]			(0.2)
Ending Balance in AOCI		(3.4)	(12.2)	(3.4)	(12.2)
Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				(3)	(1.4)
ASU 2018-02 Adoption	[1]			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
Change in Fair Value Recognized in AOCI				(0.7)
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit				0.9
Reclassification from AOCI, Net of Income Tax (Expense) Credit				0.7
Net Current Period Other Comprehensive Income (Loss)				0
ASU 2018-02 Adoption	[1]			0
Ending Balance in AOCI		0		0
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		2.3	2.5	2.2	2.9
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) Credit		(0.4)	(0.2)	(0.9)	(0.8)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(0.3)	(0.1)	(0.7)	(0.5)
Net Current Period Other Comprehensive Income (Loss)		(0.3)	(0.1)	(0.7)	(0.5)
ASU 2018-02 Adoption	[1]			0.5
Ending Balance in AOCI		2	2.4	2	2.4
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		80.4	61.1	350.8	217.1
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	(0.4)	(0.2)	(0.9)	(0.8)
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(1.3)	(1.4)	(3.9)	(4)
Amortization of Actuarial (Gains)/Losses		0.4	0.9	1	2.6
Income Tax (Expense) Credit		(0.3)	(0.3)	(0.6)	(0.8)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0	0	0	0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(1.3)	(1.4)	(3.9)	(4)
Amortization of Actuarial (Gains)/Losses		0.4	0.9	1	2.6
Income Tax (Expense) Credit		(0.2)	(0.2)	(0.6)	(0.5)
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) Credit				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)	(0.2)	(0.9)	(0.8)
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) Credit		(0.1)	(0.1)	(0.2)	(0.3)
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		(13.9)	(15.5)	(12.1)	(16.2)
Change in Fair Value Recognized in AOCI		0	0	0	0
Commodity
Generation & Marketing Revenues		619.5
Interest Rate
Interest Expense		34.5	27.5	95.6	83
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		0.4	0.5	1.5	1.5
Income Tax (Expense) Credit		(13.7)	(28.6)	(26.8)	(61.8)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.3	0.3	1.2	1
Net Current Period Other Comprehensive Income (Loss)		0.3	0.3	1.2	1
ASU 2018-02 Adoption				(2.4)
Ending Balance in AOCI		(13.6)	(15.2)	(13.6)	(15.2)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(1.7)	(4.2)	(1.4)	(4.2)
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) Credit		0	0	0	0
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0	0	0	0
Net Current Period Other Comprehensive Income (Loss)		0	0	0	0
ASU 2018-02 Adoption	[1]			(0.3)
Ending Balance in AOCI		(1.7)	(4.2)	(1.7)	(4.2)
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)				1.2	1
ASU 2018-02 Adoption	[1]			(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		(12.2)	(11.3)	(10.7)	(12)
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) Credit		0.4	0.5	1.5	1.5
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.3	0.3	1.2	1
Net Current Period Other Comprehensive Income (Loss)		0.3	0.3	1.2	1
ASU 2018-02 Adoption	[1]			(2.4)
Ending Balance in AOCI		(11.9)	(11)	(11.9)	(11)
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		48.9	32.9	167.7	101.2
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.4	0.5	1.5	1.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.2)	(0.3)	(0.6)	(0.7)
Amortization of Actuarial (Gains)/Losses		0.2	0.3	0.6	0.7
Income Tax (Expense) Credit		0.1	0.2	0.3	0.5
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0	0	0	0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.2)	(0.3)	(0.6)	(0.7)
Amortization of Actuarial (Gains)/Losses		0.2	0.3	0.6	0.7
Income Tax (Expense) Credit		0	0	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.4	0.5	1.5	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) Credit		0.1	0.2	0.3	0.5
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI				1.9
Commodity
Generation & Marketing Revenues		740.9
Interest Rate
Interest Expense		26.1	25.7	76.6	76.8
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Credit		28.1	(48.3)	(11.4)	(128)
Net Current Period Other Comprehensive Income (Loss)				(1)	(0.8)
ASU 2018-02 Adoption				0.4
Ending Balance in AOCI		1.3		1.3
Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				(1)	(0.8)
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		1.7	2.5	1.9	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) Credit		(0.5)	(0.5)	(1.3)	(1.3)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(0.4)	(0.3)	(1)	(0.8)
Net Current Period Other Comprehensive Income (Loss)		(0.4)	(0.3)	(1)	(0.8)
ASU 2018-02 Adoption	[1]			0.4
Ending Balance in AOCI		1.3	2.2	1.3	2.2
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		166.3	180.7	534.7	525.4
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(0.5)	(0.5)	(1.3)	(1.3)
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Credit		(0.1)	(0.2)	(0.3)	(0.5)
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI				2.6
Commodity
Generation & Marketing Revenues		479.1
Interest Rate
Interest Expense		16.4	13.2	47.4	40.2
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Credit		(3.6)	(27.4)	(8.6)	(42.6)
Net Current Period Other Comprehensive Income (Loss)				(0.7)	(0.6)
ASU 2018-02 Adoption				0.5
Ending Balance in AOCI		2.4		2.4
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)				(0.7)	(0.6)
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		2.6	3	2.6	3.4
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) Credit		(0.2)	(0.4)	(0.9)	(1)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(0.2)	(0.2)	(0.7)	(0.6)
Net Current Period Other Comprehensive Income (Loss)		(0.2)	(0.2)	(0.7)	(0.6)
ASU 2018-02 Adoption	[1]			0.5
Ending Balance in AOCI		2.4	2.8	2.4	2.8
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		116.8	127.8	352.3	379.8
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)	(0.4)	(0.9)	(1)
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Credit		0	(0.2)	(0.2)	(0.4)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(4.7)	(9)	(4)	(9.4)
Change in Fair Value Recognized in AOCI		2.3	0	2.3	0
Commodity
Generation & Marketing Revenues		535.6
Interest Rate
Interest Expense		32.7	31.9	95.8	92.7
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		0.1	0.3	0.3	0.9
Income Tax (Expense) Credit		(9.6)	(22.5)	(17.9)	(45.2)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.1	0.2	0.3	0.6
Net Current Period Other Comprehensive Income (Loss)		2.4	0.2	2.6	0.6
ASU 2018-02 Adoption				(1.3)
Ending Balance in AOCI		(2.3)	(8.8)	(2.3)	(8.8)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.7	(2.3)	2	(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) Credit		(0.4)	(0.3)	(1.3)	(0.8)
Reclassification from AOCI, Net of Income Tax (Expense) Credit		(0.3)	(0.2)	(1)	(0.5)
Net Current Period Other Comprehensive Income (Loss)		(0.3)	(0.2)	(1)	(0.5)
ASU 2018-02 Adoption	[1]			0.4
Ending Balance in AOCI		1.4	(2.5)	1.4	(2.5)
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)				2.6	0.6
ASU 2018-02 Adoption	[1]			(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		(6.4)	(6.7)	(6)	(7.4)
Change in Fair Value Recognized in AOCI		2.3	0	2.3	0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Credit		0.5	0.6	1.6	1.7
Reclassification from AOCI, Net of Income Tax (Expense) Credit		0.4	0.4	1.3	1.1
Net Current Period Other Comprehensive Income (Loss)		2.7	0.4	3.6	1.1
ASU 2018-02 Adoption	[1]			(1.3)
Ending Balance in AOCI		(3.7)	(6.3)	(3.7)	(6.3)
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		36.6	40	132.7	118.7
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.5	0.6	1.6	1.7
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		0.1	0.2	0.2	0.7
Income Tax (Expense) Credit		0	0.1	0	0.3
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0	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		0.1	0.2	0.2	0.7
Income Tax (Expense) Credit		(0.1)	(0.1)	(0.3)	(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	0.6	1.6	1.7
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) Credit		$ 0.1	$ 0.2	$ 0.3	$ 0.6
[1]	See Note 2 - New Accounting Pronouncements for additional information.
[2]	Amounts reclassified to the referenced line item on the statements of income.

Rate Matters - Regulated Operat

Rate Matters - Regulated Operations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 21,327.3	$ 20,760.5
Accumulated Depreciation and Amortization		17,841.6	17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		53,355.7	50,261.5
Materials and Supplies		565.6	565.5
Regulatory Liability, Noncurrent		8,643.5	8,422.3
Regulatory Assets, Noncurrent		3,189.9	3,587.6
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		352.1	350.7
Accumulated Depreciation and Amortization		1,643.9	1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,641.7	6,825.1
Materials and Supplies		51.1	52
Regulatory Liability, Noncurrent		1,346.4	1,320.5
Regulatory Assets, Noncurrent		396.4	378.7
AEP Transmission Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization	[1]	234.6	152.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	7,527	6,617.9
Materials and Supplies		16.4	13.6
Regulatory Liability, Noncurrent		509.6	493.8
Regulatory Assets, Noncurrent		15.3	11.7
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		6,490	6,446.9
Accumulated Depreciation and Amortization		4,086.2	3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,505.7	10,245.1
Materials and Supplies		98.4	99.5
Regulatory Liability, Noncurrent		1,423.8	1,454.9
Regulatory Assets, Noncurrent		475.3	573.9
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		4,579.9	4,445.9
Accumulated Depreciation and Amortization		3,113.9	3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,236.5	6,050.4
Materials and Supplies		165.7	160.6
Regulatory Liability, Noncurrent		1,791.9	1,708.7
Regulatory Assets, Noncurrent		545.3	579.4
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		2,230.6	2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,102.7	5,766.8
Materials and Supplies		38.5	41.9
Regulatory Liability, Noncurrent		1,197.7	1,100.2
Regulatory Assets, Noncurrent		389.1	652.8
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		1,576.3	1,577.2
Accumulated Depreciation and Amortization		1,461.2	1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,933.7	3,886.2
Materials and Supplies		43.4	42
Regulatory Liability, Noncurrent		850.3	853.5
Regulatory Assets, Noncurrent		352.1	368.1
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		4,655.6	4,624.9
Accumulated Depreciation and Amortization		2,798.9	2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,794	6,632
Materials and Supplies		69	67.9
Regulatory Liability, Noncurrent		896.7	896.4
Regulatory Assets, Noncurrent		217.8	220.6
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[2]	280.6	322
Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		150.4	123.4
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[2]	49.3	49.4
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		3.4	79.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.5	3.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		63.7	64.9
Storm Costs Hurricane Harvey [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		127
Storm Costs Hurricane Harvey [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		127
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		5	4
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	15.9
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	15.9
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	36.3
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	36.3
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	14.7
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		20.1	9.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.5	0.5
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		18.8	42.2
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.6	0.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		3.4	2
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		0.5	0.1
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		3.3	2.5
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		39.7	39.7
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		39.7	39.7
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		9	9.1
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		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 [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		0.2	0.1
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		4.6	4.3
Rockport Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	10.4
Shipe Road Transmission Project - FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	3.3
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[3]	151.7	128
Storm Related 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]	150.2	123.3
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	$ 3.2
Oklaunion Power Station [Member] | Generating Units Probable of Abandonment [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		106.5
Accumulated Depreciation and Amortization		56.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		49.7
Materials and Supplies		3.1
Regulatory Liability, Noncurrent		$ 5
Expected Retirement Date		2,020
Remaining Recovery Period, Plant Depreciation		28 years
Oklaunion Power Station [Member] | Public Service Co Of Oklahoma [Member] | Generating Units Probable of Abandonment [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 106.5
Accumulated Depreciation and Amortization		56.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		49.7
Materials and Supplies		3.1
Regulatory Liability, Noncurrent		$ 5
Expected Retirement Date		2,020
Remaining Recovery Period, Plant Depreciation		28 years
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[2]	In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. 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. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff.
[3]	As of September 30, 2018, AEP Texas has deferred $127 million related to Hurricane Harvey and is in the process of requesting securitization of the distribution portion of the regulatory asset.

Rate Matters - East Companies

Rate Matters - East Companies (Details)	1 Months Ended	9 Months Ended
	Oct. 25, 2018USD ($)	Sep. 30, 2018USD ($)MW	Dec. 31, 2017USD ($)
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		$ 17,841,600,000	$ 17,167,000,000
Construction Work in Progress		4,995,500,000	4,120,700,000
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		4,086,200,000	3,896,400,000
Construction Work in Progress		602,100,000	483,000,000
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		3,113,900,000	3,024,200,000
Construction Work in Progress		458,600,000	460,200,000
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		2,230,600,000	2,184,800,000
Construction Work in Progress		475,700,000	$ 410,100,000
Virginia Legislation Affecting Earnings Reviews [Member]
Public Utilities, General Disclosures [Line Items]
Fuel Expenses Not to be Recovered		10,000,000
Reduction in Annual Base Rates		50,000,000
Energy Efficiency Programs to be Requested from the Virginia SCC Through July, 2028 Dollars		$ 140,000,000
Energy Efficiency Programs to be Requested from the Virginia SCC Through July, 2028 MWs | MW		200
Virginia Legislation Affecting Earnings Reviews [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Fuel Expenses Not to be Recovered		$ 10,000,000
Reduction in Annual Base Rates		50,000,000
Energy Efficiency Programs to be Requested from the Virginia SCC Through July, 2028 Dollars		$ 140,000,000
Energy Efficiency Programs to be Requested from the Virginia SCC Through July, 2028 MWs | MW		200
2018 West Virginia Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 115,000,000
Requested Return on Common Equity		10.22%
Amount of Increase Related to Annual Depreciation Rates		$ 32,000,000
2018 West Virginia Base Rate Case [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 98,000,000
Requested Return on Common Equity		10.22%
Amount of Increase Related to Annual Depreciation Rates		$ 28,000,000
West Virginia Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		63,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		139,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		87,000,000
West Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		51,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform		125,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		77,000,000
Indiana Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 263,000,000
Requested Return on Common Equity		10.60%
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider		$ 23,000,000
Amount of Increase Related to Annual Depreciation Rates		78,000,000
Amount of Increase Related to Amortization of Regulatory Assets		11,000,000
Settled Annual Increase		$ 97,000,000
Settled Return on Common Equity		9.95%
Original Sharing of Off-System Sales Margins		50.00%
Settled Sharing of Off-System Sales Margins		95.00%
Refund for Impact of Tax Reform		$ 4,000,000
Indiana Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 263,000,000
Requested Return on Common Equity		10.60%
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider		$ 23,000,000
Amount of Increase Related to Annual Depreciation Rates		78,000,000
Amount of Increase Related to Amortization of Regulatory Assets		11,000,000
Settled Annual Increase		$ 97,000,000
Settled Return on Common Equity		9.95%
Original Sharing of Off-System Sales Margins		50.00%
Settled Sharing of Off-System Sales Margins		95.00%
Refund for Impact of Tax Reform		$ 4,000,000
Michigan Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 52,000,000
Requested Return on Common Equity		10.60%
Amount of Increase Related to Annual Depreciation Rates		$ 23,000,000
Amount of Increase Related to Amortization of Regulatory Assets		4,000,000
ALJ Recommended Annual Increase		49,000,000
Cost of New Entry Value		$ 289
ALJ Recommended Return on Common Equity		9.80%
Alternate Supplier Cap		10.00%
Reduced Capacity Charge Pretax Loss		$ 9,000,000
Approved Annual Revenue Increase		$ 50,000,000
Approved Return On Equity		9.90%
Michigan Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 52,000,000
Requested Return on Common Equity		10.60%
Amount of Increase Related to Annual Depreciation Rates		$ 23,000,000
Amount of Increase Related to Amortization of Regulatory Assets		4,000,000
ALJ Recommended Annual Increase		49,000,000
Cost of New Entry Value		$ 289
ALJ Recommended Return on Common Equity		9.80%
Alternate Supplier Cap		10.00%
Reduced Capacity Charge Pretax Loss		$ 9,000,000
Approved Annual Revenue Increase		$ 50,000,000
Approved Return On Equity		9.90%
Michigan Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		$ 9,000,000
Michigan Tax Reform [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		9,000,000
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		274,000,000
Approved Capital Costs		274,000,000
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		274,000,000
Approved Capital Costs		274,000,000
Kentucky Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
KPSC Order Annual Revenue Increase		$ 12,000,000
KPSC Order Return on Common Equity		9.70%
KPSC Order Annual Revenue Reduction due to Tax Reform		$ 14,000,000
KPSC Order Deferral of Rockport Plant Unit Power Agreement Expenses		$ 50,000,000
Recovery/Return of certain PJM OATT Expenses Above/Below Corresponding Level Recovered in Rates		80.00%
KPCo Request for Additional Revenue Increase		$ 2,300,000
KPSC Order Additional Annual Revenue Increase		765,000
Kentucky Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Associated with Certain Depreciable Property		82,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		93,000,000
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
PUCO Approved Reduced Customer Credits		$ 15,000,000
Solar Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW		400
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW		500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement		100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement		50.00%
Return on Common Equity Filed in the Pending Stipulation Agreement		10.00%
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
PUCO Approved Reduced Customer Credits		$ 15,000,000
Solar Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW		400
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW		500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement		100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement		50.00%
Return on Common Equity Filed in the Pending Stipulation Agreement		10.00%
2016 SEET Filing [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		$ 58,000,000
Intervenor Recommended Refund to Customers		53,000,000
2016 SEET Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		58,000,000
Intervenor Recommended Refund to Customers		53,000,000
PJM Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Amount of RTEP Refunds Recorded to Customer Accounts Receivable		134,000,000
Amount of RTEP Refunds Recorded to Deferred Charges and Other Noncurrent Assets		$ 75,000,000
FERC Transmission Complaint - AEP PJM Participants [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		10.99%
Intervenor Recommended Return on Common Equity		8.32%
Return On Common Equity Per Settlement Agreement		9.85%
Return on Common Equity Inclusive of RTO Per Settlement Agreement		10.35%
RTO Incentive Adder Per Settlement Agreement		0.50%
One Time Refund to Customers Per Settlement Agreement		$ 50,000,000
Increased Cap on Equity Portion of the Capital Structure Per Settlement Agreement		55.00%
Original Cap on Equity Portion of the Capital Structure Prior to Settlement Agreement		50.00%
Second Intervenor Recommended Return on Common Equity		8.48%
Second Intervenor Recommended One Time Refund to Customers		$ 184,000,000
FERC Trial Staff Recommended Return on Common Equity		8.41%
FERC Trial Staff Recommended One Time Refund to Customers		$ 175,000,000
Subsequent Event [Member] | Virginia Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Not Subject to Rate Normalization Requirements to Offset Fuel	$ 55,000,000
Refund Due to Tax Reform	7,000,000
Refund for Current Year Tax Reform Rate Change	39,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property	7,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements	11,000,000
Subsequent Event [Member] | Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Excess ADIT Not Subject to Rate Normalization Requirements to Offset Fuel	55,000,000
Refund Due to Tax Reform	7,000,000
Refund for Current Year Tax Reform Rate Change	39,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property	7,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements	11,000,000
Subsequent Event [Member] | 2018 West Virginia Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted Annual Increase Request due to Tax Reform	95,000,000
Staff Recommended Annual Increase	$ 2,000,000
Staff Recommended Return on Common Equity	9.25%
Intervenor Recommended Annual Decrease	$ 14,000,000
Intervenor Recommended Return on Common Equity	8.75%
Subsequent Event [Member] | 2018 West Virginia Base Rate Case [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted Annual Increase Request due to Tax Reform	$ 80,000,000
Staff Recommended Annual Increase	$ 2,000,000
Staff Recommended Return on Common Equity	9.25%
Intervenor Recommended Annual Decrease	$ 14,000,000
Intervenor Recommended Return on Common Equity	8.75%
Subsequent Event [Member] | Michigan Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change	$ 3,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property	68,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements	37,000,000
Subsequent Event [Member] | Michigan Tax Reform [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change	3,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property	68,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements	37,000,000
Subsequent Event [Member] | Ohio Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform	20,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform	48,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property	278,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements	129,000,000
Subsequent Event [Member] | Ohio Tax Reform [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform	20,000,000
Regulatory Assets Used to Offset Tax Savings and Excess ADIT Due to Tax Reform	48,000,000
Refund for Excess ADIT Associated with Certain Depreciable Property	278,000,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements	$ 129,000,000
Minimum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		215,000,000
Minimum [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		215,000,000
Maximum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		290,000,000
Maximum [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		$ 290,000,000

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Oct. 25, 2018	Sep. 30, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 4,995,500	$ 4,120,700
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		1,108,800	835,700
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		85,700	111,300
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		234,500	$ 233,200
AEP Texas Interim Transmission and Distribution Rates [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		959,000
Net Increase in Transmission Rates		22,000
Increase in Transmission Rates Due to Capital Investments		46,000
Reduction in Transmission Rates Due to Tax Reform		24,000
Net Decrease In DCRF		24,000
Increase in Distribution Rates Due to Capital Investments		19,000
Refund for Current Year Tax Reform Rate Change		21,000
Refund for Excess ADIT Associated with Certain Depreciable Property		10,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		12,000
AEP Texas Interim Transmission and Distribution Rates [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		959,000
Net Increase in Transmission Rates		22,000
Increase in Transmission Rates Due to Capital Investments		46,000
Reduction in Transmission Rates Due to Tax Reform		24,000
Net Decrease In DCRF		24,000
Increase in Distribution Rates Due to Capital Investments		19,000
Refund for Current Year Tax Reform Rate Change		21,000
Refund for Excess ADIT Associated with Certain Depreciable Property		10,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		12,000
Hurricane Harvey Storm [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates		1,000
AEP Texas Total Storm-Related Costs		150,000
AEP Texas Hurricane Harvey Storm-Related Costs		127,000
AEP Texas Hurricane Harvey Storm-Capital Expenditures		205,000
Hurricane Harvey Storm Insurance Proceeds Received		10,000
AEP Texas Hurricane Harvey Storm-Insurance Proceeds to be Received		4,000
Determination of System Restoration Costs for Total Estimated Storm Costs		425,000
Determination of System Restoration Costs for Total Estimated Storm Costs Net of Offsets		370,000
Amount of Securitization Request for Distribution Related Assets		253,000
Amount of Transmission Related Assets to be Recovered at a Later Time		117,000
Hurricane Harvey Storm [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates		1,000
AEP Texas Total Storm-Related Costs		150,000
AEP Texas Hurricane Harvey Storm-Related Costs		127,000
AEP Texas Hurricane Harvey Storm-Capital Expenditures		205,000
Hurricane Harvey Storm Insurance Proceeds Received		10,000
AEP Texas Hurricane Harvey Storm-Insurance Proceeds to be Received		4,000
Determination of System Restoration Costs for Total Estimated Storm Costs		425,000
Determination of System Restoration Costs for Total Estimated Storm Costs Net of Offsets		370,000
Amount of Securitization Request for Distribution Related Assets		253,000
Amount of Transmission Related Assets to be Recovered at a Later Time		117,000
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Reduction in Transmission Rates Due to Tax Reform		28,000
Refund for Current Year Tax Reform Rate Change		$ 11,000
Parent Ownership Interest In ETT		50.00%
AEP Share Of ETT Cumulative Revenues Subject To Review		$ 849,000
Oklahoma Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change		3,000
Refund for Excess ADIT Associated with Certain Depreciable Property		353,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		72,000
Oklahoma Tax Reform [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change		3,000
Refund for Excess ADIT Associated with Certain Depreciable Property		353,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 72,000
FERC Transmission Complaint - AEP SPP Participants [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		10.70%
Second Intervenor Recommended Return on Common Equity		8.71%
Intervenor Recommended Return on Common Equity		8.36%
2012 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		$ 114,000
Resulting Approved Base Rate Increase		52,000
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114,000
Resulting Approved Base Rate Increase		52,000
2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Net Increase in Texas Annual Revenues		$ 69,000
Requested Return on Common Equity		10.00%
Approved Net Increase in Texas Annual Revenues		$ 50,000
Approved Return on Common Equity		9.60%
Approved Additional Vegetation Management Expenses		$ 2,000
Impairment Charge Total		19,000
Impairment Charge Welsh Plant, Unit 2		7,000
Impairment Charge Disallowed Plant Investments		12,000
Additional Revenues Recognized to be Surcharged to Customers		32,000
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management		7,000
Proposed Revenue Reduction Due to Tax Reform		18,000
Approved Reduction in Residential Rates Due to Tax Reform		8,000
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Net Increase in Texas Annual Revenues		$ 69,000
Requested Return on Common Equity		10.00%
Approved Net Increase in Texas Annual Revenues		$ 50,000
Approved Return on Common Equity		9.60%
Approved Additional Vegetation Management Expenses		$ 2,000
Impairment Charge Total		19,000
Impairment Charge Welsh Plant, Unit 2		7,000
Impairment Charge Disallowed Plant Investments		12,000
Additional Revenues Recognized to be Surcharged to Customers		32,000
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management		7,000
Proposed Revenue Reduction Due to Tax Reform		18,000
Approved Reduction in Residential Rates Due to Tax Reform		8,000
Louisiana 2015 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14,000
Louisiana 2015 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14,000
Louisiana 2017 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		31,000
Louisiana 2017 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		31,000
Louisiana 2018 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		28,000
Adjusted Requested Annual Increase		18,000
Louisiana 2018 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		28,000
Adjusted Requested Annual Increase		18,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		550,000
Construction Work in Progress		399,000
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79,000
Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs		131,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		10,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		6,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		550,000
Construction Work in Progress		399,000
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79,000
Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs		131,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		10,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		6,000
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		621,000
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		621,000
Arkansas Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		655
Refund for Current Year Tax Reform Rate Change		7,000
Refund for Excess ADIT Associated with Certain Depreciable Property		66,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		11,000
Arkansas Tax Reform [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund Due to Tax Reform		655
Refund for Current Year Tax Reform Rate Change		7,000
Refund for Excess ADIT Associated with Certain Depreciable Property		66,000
Refund for Excess ADIT Not Subject to Rate Normalization Requirements		$ 11,000
FERC SWEPCo Power Supply Agreements Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		11.10%
Intervenor Recommended Return on Common Equity		8.41%
Agreed Upon Return on Common Equity		10.10%
Agreed Upon One-Time Billing Credit		$ 287
Subsequent Event [Member] | Hurricane Harvey Storm [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Requested Reduction in Amount of Securitization for Distribution Related Assets	$ 24,000
PUCT Staff Requested Reduction in Amount of Securitization for Distribution Related Assets	4,000
Subsequent Event [Member] | Hurricane Harvey Storm [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Requested Reduction in Amount of Securitization for Distribution Related Assets	24,000
PUCT Staff Requested Reduction in Amount of Securitization for Distribution Related Assets	4,000
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Net Increase	88,000
Amount of Increase Related to Increased Storm Expense Amortization	$ 7,000
Requested Return on Common Equity	10.30%
Amount of Increase Related to Annual Depreciation Rates	$ 13,000
Subsequent Event [Member] | 2018 Oklahoma Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Net Increase	88,000
Amount of Increase Related to Increased Storm Expense Amortization	$ 7,000
Requested Return on Common Equity	10.30%
Amount of Increase Related to Annual Depreciation Rates	$ 13,000
Subsequent Event [Member] | Texas Tax Reform [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change	10,000
Subsequent Event [Member] | Texas Tax Reform [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change	10,000
Subsequent Event [Member] | Louisiana 2017 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Resulting Approved Base Rate Increase	31,000
Subsequent Event [Member] | Louisiana 2017 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Resulting Approved Base Rate Increase	31,000
Subsequent Event [Member] | Louisiana 2018 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change	11,000
Subsequent Event [Member] | Louisiana 2018 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Refund for Current Year Tax Reform Rate Change	$ 11,000

Commitments, Guarantees and C_3

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Oct. 25, 2018
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	$ 71.8
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	45
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Letters of Credit Limit	1,200
Uncommitted Facility	305
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	140
Estimated Final Cost Mine Reclamation	79
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	74
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	79
Amount Collected, Rider Mine Close Other Assets Noncurrent	5
Guarantees of Equity Method Investees [Member]
Maximum Potential Amount of Future Payments Associated with Guarantee	75
Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	47.7
Boat and Barge Leases [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases	46
Guarantee Liability related to AEPRO Boat and Barge Leases	6
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Current Liabilities	1
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Noncurrent Liabilities	5
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	2.8
AEP Texas Inc. [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	11.4
Appalachian Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	8.8
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3.5
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligations for Remaining Railcars	$ 7
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee	$ 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	0.6
Ohio Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	7.6
Public Service Co Of Oklahoma [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	4.1
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	140
Estimated Final Cost Mine Reclamation	79
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	74
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	79
Amount Collected, Rider Mine Close Other Assets Noncurrent	5
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	4.2
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligations for Remaining Railcars	$ 7
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee	$ 5
July 2019 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Bilateral Letters of Credit, Matured	46
June 2021 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	$ 3,000
Subsequent Event [Member] | June 2022 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		$ 4,000

Dispostions and Impairments (De

Dispostions and Impairments (Details)	3 Months Ended					9 Months Ended
	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Mar. 31, 2017USD ($)MW	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2016
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	$ 826,000,000			$ 644,000,000		$ 2,332,700,000	$ 1,884,100,000
AEP Texas Inc. [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	133,400,000			117,500,000		368,400,000	332,800,000
AEP Transmission Co [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	24,500,000			18,400,000		59,600,000	38,800,000
Appalachian Power Co [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	131,900,000			117,000,000		380,000,000	370,100,000
Indiana Michigan Power Co [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	149,300,000			142,000,000		425,800,000	438,800,000
Ohio Power Co [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	215,200,000			126,900,000		586,400,000	380,900,000
Public Service Co Of Oklahoma [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	106,300,000			84,500,000		286,800,000	228,900,000
Southwestern Electric Power Co [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations	99,100,000			$ 81,200,000		292,000,000	$ 234,900,000
Generation And Marketing [Member] | Racine Hydroelectric Plant [Member]
Discontinued Operations and Disposal Groups (Textuals)
Property, Plant, and Equipment, Fair Value Disclosure	0		$ 0			$ 0
Other Asset Impairment Charges	$ 35,000,000		$ 43,000,000
Generation And Marketing [Member] | Merchant Coal-Fired Generation Assets [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations					$ 4,000,000
Generation And Marketing [Member] | Zimmer Plant Assets [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations					$ 7,000,000
Corporate and Other [Member] | Other Assets [Member]
Discontinued Operations and Disposal Groups (Textuals)
Utilities Operating Expense, Operations		$ 21,000,000
Gavin, Waterford, Darby and Lawrenceburg Plants [Member] | Generation And Marketing [Member]
Competitive generation assets sold to a nonaffiliated party (in MWs). | MW					5,329
Proceeds from Sales of Assets, Investing Activities					$ 2,200,000,000
Discontinued Operations and Disposal Groups (Textuals)
Cash Proceeds from Sale of Disposition Plants, Net					1,200,000,000
Pre-tax Gain on Sale of Plants					$ 226,000,000
Coal [Member] | Wm. H. Zimmer Generating Station [Member] | Generation And Marketing [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share								25.40%

Benefit Plans (Details)

Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 24.4	$ 24.1	$ 73.2	$ 72.3
Interest Cost	46.9	50.7	140.8	152.3
Expected Return on Plan Assets	(72.6)	(71.1)	(217.7)	(213.5)
Amortization of Prior Service Cost (Credit)	0	0.3	0	0.8
Amortization of Net Actuarial Loss	21.3	20.7	63.9	62.1
Net Periodic Benefit Cost (Credit)	20	24.7	60.2	74
Pension Plans [Member] | AEP Texas Inc. [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.3	2.1	6.9	6.4
Interest Cost	4	4.3	12	12.9
Expected Return on Plan Assets	(6.4)	(6.2)	(19.2)	(18.8)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.8	1.7	5.4	5.2
Net Periodic Benefit Cost (Credit)	1.7	1.9	5.1	5.7
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.4	2.3	7	7
Interest Cost	5.8	6.5	17.6	19.3
Expected Return on Plan Assets	(9.1)	(8.9)	(27.4)	(26.8)
Amortization of Prior Service Cost (Credit)	0	0	0	0.1
Amortization of Net Actuarial Loss	2.6	2.6	7.9	7.8
Net Periodic Benefit Cost (Credit)	1.7	2.5	5.1	7.4
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3.4	3.5	10.2	10.5
Interest Cost	5.6	6.1	16.6	18.2
Expected Return on Plan Assets	(9)	(8.6)	(26.8)	(25.9)
Amortization of Prior Service Cost (Credit)	0	0	0	0.1
Amortization of Net Actuarial Loss	2.5	2.4	7.4	7.3
Net Periodic Benefit Cost (Credit)	2.5	3.4	7.4	10.2
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2	1.8	5.8	5.6
Interest Cost	4.4	4.8	13.3	14.5
Expected Return on Plan Assets	(7.2)	(6.9)	(21.6)	(20.9)
Amortization of Prior Service Cost (Credit)	0	0	0	0.1
Amortization of Net Actuarial Loss	2	2	6	5.9
Net Periodic Benefit Cost (Credit)	1.2	1.7	3.5	5.2
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.7	1.7	5.3	4.9
Interest Cost	2.5	2.6	7.4	8
Expected Return on Plan Assets	(4)	(3.9)	(12.1)	(11.8)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.1	1.1	3.3	3.3
Net Periodic Benefit Cost (Credit)	1.3	1.5	3.9	4.4
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.4	2.1	7	6.5
Interest Cost	2.8	3.1	8.5	9.2
Expected Return on Plan Assets	(4.4)	(4.2)	(13.1)	(12.6)
Amortization of Prior Service Cost (Credit)	0	0	0	0
Amortization of Net Actuarial Loss	1.3	1.3	3.8	3.7
Net Periodic Benefit Cost (Credit)	2.1	2.3	6.2	6.8
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.9	2.8	8.7	8.4
Interest Cost	11.8	14.8	35.5	44.5
Expected Return on Plan Assets	(25.6)	(25.3)	(76.7)	(76)
Amortization of Prior Service Cost (Credit)	(17.3)	(17.3)	(51.8)	(51.8)
Amortization of Net Actuarial Loss	2.7	9.2	7.9	27.5
Net Periodic Benefit Cost (Credit)	(25.5)	(15.8)	(76.4)	(47.4)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.3	0.7	0.7
Interest Cost	0.9	1.2	2.8	3.7
Expected Return on Plan Assets	(2.1)	(2.2)	(6.4)	(6.6)
Amortization of Prior Service Cost (Credit)	(1.5)	(1.5)	(4.4)	(4.4)
Amortization of Net Actuarial Loss	0.2	0.8	0.6	2.4
Net Periodic Benefit Cost (Credit)	(2.2)	(1.4)	(6.7)	(4.2)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.3	0.8	0.8
Interest Cost	2.1	2.6	6.2	7.9
Expected Return on Plan Assets	(4)	(4.1)	(12)	(12.3)
Amortization of Prior Service Cost (Credit)	(2.5)	(2.5)	(7.5)	(7.5)
Amortization of Net Actuarial Loss	0.4	1.6	1.4	4.7
Net Periodic Benefit Cost (Credit)	(3.7)	(2.1)	(11.1)	(6.4)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.4	0.4	1.2	1.2
Interest Cost	1.4	1.7	4.1	5.2
Expected Return on Plan Assets	(3.1)	(3.1)	(9.3)	(9.2)
Amortization of Prior Service Cost (Credit)	(2.4)	(2.3)	(7.1)	(7)
Amortization of Net Actuarial Loss	0.3	1.1	0.9	3.3
Net Periodic Benefit Cost (Credit)	(3.4)	(2.2)	(10.2)	(6.5)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.3	0.7	0.7
Interest Cost	1.3	1.6	3.9	5
Expected Return on Plan Assets	(2.9)	(3)	(8.8)	(9)
Amortization of Prior Service Cost (Credit)	(1.7)	(1.7)	(5.2)	(5.2)
Amortization of Net Actuarial Loss	0.3	1.1	0.8	3.3
Net Periodic Benefit Cost (Credit)	(2.8)	(1.7)	(8.6)	(5.2)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.1	0.2	0.5	0.5
Interest Cost	0.6	0.8	1.8	2.4
Expected Return on Plan Assets	(1.3)	(1.4)	(4.1)	(4.2)
Amortization of Prior Service Cost (Credit)	(1.1)	(1.1)	(3.2)	(3.2)
Amortization of Net Actuarial Loss	0.1	0.5	0.4	1.5
Net Periodic Benefit Cost (Credit)	(1.6)	(1)	(4.6)	(3)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.7	0.6
Interest Cost	0.7	0.9	2.1	2.7
Expected Return on Plan Assets	(1.6)	(1.5)	(4.8)	(4.7)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.3)	(3.9)	(3.9)
Amortization of Net Actuarial Loss	0.2	0.5	0.5	1.7
Net Periodic Benefit Cost (Credit)	$ (1.8)	$ (1.2)	$ (5.4)	$ (3.6)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2018		Sep. 30, 2017		Dec. 31, 2017
Reportable Segment Information
Revenue from Contracts with Customers		$ 4,333.1		$ 4,104.7		$ 12,394.6		$ 11,614.5
Sales to AEP Affiliates		0		0		0		0
Total Revenues		4,333.1		4,104.7		12,394.6		11,614.5
Interest Expense		256.8		223.3		733.1		668
Income Tax Expense		(80.7)		264		93.5		797.8
Net Income (Loss)		579.7		556.7		1,566.5		1,527.1
Balance Sheet Information
Total Property, Plant and Equipment		71,197.3				71,197.3				$ 67,428.5
Accumulated Depreciation and Amortization		17,841.6				17,841.6				17,167
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		53,355.7				53,355.7				50,261.5
Total Assets		67,617.4				67,617.4				64,729.1
Long-term Debt Due Within One Year		1,904.2				1,904.2				1,753.7
Long-term Debt - Affiliated		0				0				0
Long-term Debt		20,869.8				20,869.8				19,419.6
Total Long-term Debt Outstanding		22,774				22,774				21,173.3
Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,610.2		2,453.8		7,332.4		6,819.3
Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,180.9		1,149.7		3,450		3,242.7
Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		486.5		441.5		1,399.3		1,386.8
Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		55.5		59.7		212.9		165.7
Total Revenues		58.6	[1]			78.5	[2]
AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers	[3]	206.8
Sales to AEP Affiliates		148.4		130.1	[4]	453.8	[4]	439.1	[4]
Total Revenues		194.4	[3]	165.6	[4]	586.2	[3],[4]	534.8	[4]
Interest Income		0.5		0.2	[4]	1.3	[4]	0.5	[4]
Interest Expense		19.8		17.1	[4]	60.7	[4]	50.4	[4]
Income Tax Expense		17.6		29.5	[4]	63.7	[4]	108.2	[4]
Net Income (Loss)		78.1		58.6	[4]	244.2	[4]	212.4	[4]
Balance Sheet Information
Total Property, Plant and Equipment	[4]	7,761.6				7,761.6				6,770.5
Accumulated Depreciation and Amortization	[4]	234.6				234.6				152.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[4]	7,527				7,527				6,617.9
Notes Receivable, Related Parties		0				0				0
Total Assets	[4]	7,998.4				7,998.4				7,082.1
Long-term Debt Due Within One Year		50				50				50
Long-term Debt		2,822.6				2,822.6				2,500.4
Total Long-term Debt Outstanding		2,872.6				2,872.6				2,550.4
AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		46		35.6	[4]	132.3	[4]	95.7	[4]
AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		(0.1)	[4]	0.1	[4]	0	[4]
Total Revenues	[3]	0	[5]			0	[6]
Reconciling Adjustments [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		0		0		0
Sales to AEP Affiliates		(247.6)		(226.1)		(674.1)		(727.9)
Total Revenues		(247.6)		(226.1)		(674.1)		(727.9)
Net Income (Loss)		0		0		0		0
Balance Sheet Information
Total Property, Plant and Equipment	[7]	(354.4)				(354.4)				(366.4)
Accumulated Depreciation and Amortization	[7]	(186.4)				(186.4)				(186.9)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[7]	(168)				(168)				(179.5)
Total Assets	[7],[8]	(3,398)				(3,398)				(3,022)
Long-term Debt Due Within One Year		0				0				0
Long-term Debt - Affiliated		(82.2)				(82.2)				(82.2)
Long-term Debt		0				0				0
Total Long-term Debt Outstanding		(82.2)				(82.2)				(82.2)
Reconciling Adjustments [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues		43	[1]			0	[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	[9]	(25.7)		(19.3)		(75.3)		(57.6)
Interest Expense	[9]	(25.7)		(19.3)		(75.3)		(57.6)
Income Tax Expense		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	[10]	(2,900)				(2,900)				(2,550.4)
Total Assets	[11]	(2,973.6)				(2,973.6)				(2,594.9)
Total Long-term Debt Outstanding	[10]	(2,900)				(2,900)				(2,575)
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		26.5		28.4		61.3		73.8
Total Revenues		2,636.7		2,482.2		7,393.7		6,893.1
Net Income (Loss)		345.6		297.3		856.3		639.2
Balance Sheet Information
Total Property, Plant and Equipment		44,553.4				44,553.4				43,294.4
Accumulated Depreciation and Amortization		13,703.3				13,703.3				13,153.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		30,850.1				30,850.1				30,141
Total Assets		38,813.2				38,813.2				37,579.7
Long-term Debt Due Within One Year		1,306.1				1,306.1				1,038.1
Long-term Debt - Affiliated		50				50				50
Long-term Debt		11,563.5				11,563.5				10,801.4
Total Long-term Debt Outstanding		12,919.6				12,919.6				11,889.5
Vertically Integrated Utilities [Member] | Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,610.2		2,453.8		7,332.4		6,819.3
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues		9.8	[1]			1.1	[2]
Transmission And Distribution Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates		30.6		23.6		60.9		70.5
Total Revenues		1,211.5		1,173.3		3,510.9		3,313.2
Net Income (Loss)		145.2		144		384.6		374.3
Balance Sheet Information
Total Property, Plant and Equipment		17,619.1				17,619.1				16,371.2
Accumulated Depreciation and Amortization		3,856.7				3,856.7				3,768.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		13,762.4				13,762.4				12,602.9
Total Assets		16,399.1				16,399.1				16,060.7
Long-term Debt Due Within One Year		548.5				548.5				663.1
Long-term Debt - Affiliated		0				0				0
Long-term Debt		5,082.2				5,082.2				4,705.4
Total Long-term Debt Outstanding		5,630.7				5,630.7				5,368.5
Transmission And Distribution Utilities [Member] | Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,180.9		1,149.7		3,450		3,242.7
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues		8.9	[1]			51.9	[2]
AEP Transmission Holdco [Member]
Reportable Segment Information
Sales to AEP Affiliates		135.3		133.4		408.7		456.1
Total Revenues		187.2		178.5		605.2		581.9
Net Income (Loss)		74.2		76.5		280.9		278.3
Balance Sheet Information
Total Property, Plant and Equipment		8,130.3				8,130.3				7,110.2
Accumulated Depreciation and Amortization		244.3				244.3				176.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,886				7,886				6,933.6
Total Assets		9,127.7				9,127.7				8,141.8
Long-term Debt Due Within One Year		50				50				50
Long-term Debt - Affiliated		0				0				0
Long-term Debt		2,966.2				2,966.2				2,631.3
Total Long-term Debt Outstanding		3,016.2				3,016.2				2,681.3
AEP Transmission Holdco [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		51.9		45.1		196.5		125.8
Generation And Marketing [Member]
Reportable Segment Information
Sales to AEP Affiliates		35.1		24		88.1		80.7
Total Revenues		521.6		465.5		1,487.4		1,467.5
Net Income (Loss)		5.1		33.7		61.8		246.3
Balance Sheet Information
Total Property, Plant and Equipment		864.1				864.1				644.6
Accumulated Depreciation and Amortization		40.1				40.1				75
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		824				824				569.6
Total Assets		2,369.3				2,369.3				2,009.8
Long-term Debt Due Within One Year		0.1				0.1				0
Long-term Debt - Affiliated		32.2				32.2				32.2
Long-term Debt		(0.3)				(0.3)				(0.3)
Total Long-term Debt Outstanding		32				32				31.9
Generation And Marketing [Member] | Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		486.5		441.5		1,399.3		1,386.8
Generation And Marketing [Member] | Other Revenues [Member]
Reportable Segment Information
Total Revenues		(5.3)	[1]			18.8	[2]
All Other [Member]
Reportable Segment Information
Sales to AEP Affiliates	[12]	20.1		16.7		55.1		46.8
Total Revenues	[12]	23.7		31.3		71.5		86.7
Net Income (Loss)	[12]	9.6		5.2		(17.1)		(11)
Balance Sheet Information
Total Property, Plant and Equipment	[12]	384.8				384.8				374.5
Accumulated Depreciation and Amortization	[12]	183.6				183.6				180.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[12]	201.2				201.2				193.9
Total Assets	[12],[13]	4,306.1				4,306.1				3,959.1
Long-term Debt Due Within One Year	[12]	(0.5)				(0.5)				2.5
Long-term Debt - Affiliated	[12]	0				0				0
Long-term Debt	[12]	1,258.2				1,258.2				1,281.8
Total Long-term Debt Outstanding	[12]	1,257.7				1,257.7				1,284.3
All Other [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers	[12]	3.6		14.6		16.4		39.9
Total Revenues		2.2	[1]			6.7	[2]
State Transcos [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		148.4		130.1	[4]	453.8	[4]	439.1	[4]
Total Revenues		194.4		165.6	[4]	586.2	[4]	534.8	[4]
Interest Income		0.2		0	[4]	0.4	[4]	0.1	[4]
Interest Expense		19.8		17.1	[4]	60.7	[4]	50.4	[4]
Income Tax Expense		18.4		29.5	[4]	63.7	[4]	108	[4]
Net Income (Loss)		77.1		58.5	[4]	243.6	[4]	212.1	[4]
Balance Sheet Information
Total Property, Plant and Equipment	[4]	7,761.6				7,761.6				6,770.5
Accumulated Depreciation and Amortization	[4]	234.6				234.6				152.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[4]	7,527				7,527				6,617.9
Notes Receivable, Related Parties		0				0				0
Total Assets	[4]	7,983.6				7,983.6				7,086.9
Total Long-term Debt Outstanding		2,900				2,900				2,575
State Transcos [Member] | AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		46		35.6	[4]	132.3	[4]	95.7	[4]
State Transcos [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		(0.1)	[4]	0.1	[4]	0	[4]
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		26		19.5		76.2		58
Interest Expense		25.7		19.3		75.3		57.6
Income Tax Expense		(0.8)		0		0		0.2
Net Income (Loss)	[14]	1		0.1		0.6		0.3
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		2,900				2,900				2,550.4
Total Assets	[15]	2,988.4				2,988.4				2,590.1
Total Long-term Debt Outstanding		2,872.6				2,872.6				$ 2,550.4
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]	Amounts include affiliated and nonaffiliated revenues.
[2]	Amounts include affiliated and nonaffiliated revenues.
[3]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[4]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[5]	Amounts include affiliated and nonaffiliated revenues.
[6]	Amounts include affiliated and nonaffiliated revenues.
[7]	Includes eliminations due to an intercompany capital lease.
[8]	Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
[9]	Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
[10]	Elimination of intercompany debt.
[11]	Primarily relates to the elimination of Notes Receivable from the State Transcos.
[12]	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 and interest expense and other nonallocated costs.
[13]	Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
[14]	Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
[15]	Includes the elimination of AEPTCo Parent’s investments in State Transcos.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, T in Millions, MWh in Millions, MMBTU in Millions		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2018USD ($)MWhMMBTUTgal		Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)MWhMMBTUTgal		Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)MWhMMBTUTgal
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 15,000,000			$ 15,000,000			$ 9,400,000
Cash Collateral Paid Netted Against Risk Management Liabilities		1,000,000			1,000,000			9,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		191,900,000			191,900,000			126,200,000
Long-term Risk Management Assets		264,900,000			264,900,000			282,100,000
Total Assets		456,800,000			456,800,000			408,300,000
Current Risk Management Liabilities		57,300,000			57,300,000			61,600,000
Long-term Risk Management Liabilities		287,200,000			287,200,000			322,000,000
Total Liabilities		344,500,000			344,500,000			383,600,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		39,800,000		$ 26,600,000	268,800,000		$ 106,300,000
Carrying Amount of Hedged Asset (Liability)	[1]	(461,400,000)			(461,400,000)			(489,300,000)
Cumulative Fair Value Hedging Adjustment in the Carrying Amount of the Hedged Asset (Liability)	[1]	34,200,000			34,200,000			6,100,000
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments	[2]	(6,300,000)		100,000	(28,100,000)		(100,000)
Gain (Loss) on Fair Value Portion of Long Term Debt	[2]	6,300,000		(100,000)	28,100,000		100,000
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		253,100,000			253,100,000			243,600,000
Amount of Cash Collateral Posted		800,000			800,000			1,300,000
Additional Settlement Liability if Cross Default Provision is Triggered		211,200,000			$ 211,200,000			223,100,000
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows					183 months
Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		68,400,000			$ 68,400,000			24,900,000
Long-term Risk Management Assets		1,400,000			1,400,000			1,100,000
Current Risk Management Liabilities		900,000			900,000			1,300,000
Long-term Risk Management Liabilities		700,000			700,000			200,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		24,000,000		4,500,000	133,800,000		30,500,000
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		100,000			100,000			600,000
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		100,000			100,000			500,000
AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		500,000			500,000			500,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		200,000		400,000	600,000		0
Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		10,900,000			10,900,000			7,600,000
Long-term Risk Management Assets		900,000			900,000			700,000
Current Risk Management Liabilities		6,400,000			6,400,000			3,500,000
Long-term Risk Management Liabilities		400,000			400,000			100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(3,400,000)		2,100,000	4,800,000		21,100,000
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0			400,000
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0			400,000
Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		600,000			600,000			600,000
Long-term Risk Management Assets		100,000			100,000			0
Current Risk Management Liabilities		5,400,000			5,400,000			6,400,000
Long-term Risk Management Liabilities		89,800,000			89,800,000			126,000,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(9,100,000)		(8,500,000)	33,000,000		(25,700,000)
Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		18,500,000			18,500,000			6,400,000
Current Risk Management Liabilities		600,000			600,000			0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		3,500,000		2,600,000	34,600,000		13,700,000
Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		6,500,000			6,500,000			6,400,000
Current Risk Management Liabilities		200,000			200,000			200,000
Long-term Risk Management Liabilities		2,600,000			2,600,000			0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,100,000		7,200,000	6,400,000		22,100,000
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		2,800,000			2,800,000			200,000
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		2,800,000			2,800,000			100,000
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[3]	421,100,000	[4]		421,100,000	[4]		383,800,000	[5]
Total Liabilities	[3]	251,400,000	[4]		251,400,000	[4]		309,500,000	[5]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	69,800,000			69,800,000			26,000,000
Total Liabilities	[3],[6]	1,600,000			1,600,000			1,500,000
Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Total Assets	[3]	500,000			500,000			500,000
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	11,800,000			11,800,000			8,300,000
Total Liabilities	[3],[6]	6,800,000			6,800,000			3,600,000
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	700,000			700,000			600,000
Total Liabilities	[3],[6]	95,200,000			95,200,000			132,400,000
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	18,500,000			18,500,000			6,400,000
Total Liabilities	[3],[6]	600,000			600,000			0
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	6,500,000			6,500,000			6,400,000
Total Liabilities	[3],[6]	2,800,000			2,800,000			200,000
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(22,800,000)			(22,800,000)			(28,400,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					14,400,000			5,500,000
Derivatives and Hedging (Textuals) [Abstract]
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]	359,900,000			359,900,000			389,000,000
Long-term Risk Management Assets	[7]	295,300,000			295,300,000			300,900,000
Total Assets	[7]	655,200,000			655,200,000			689,900,000
Current Risk Management Liabilities	[7]	232,400,000			232,400,000			334,600,000
Long-term Risk Management Liabilities	[7]	240,000,000			240,000,000			280,600,000
Total Liabilities	[7]	472,400,000			472,400,000			615,200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	182,800,000			182,800,000			74,700,000
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	106,600,000			106,600,000			75,600,000
Long-term Risk Management Assets	[7]	6,000,000			6,000,000			2,400,000
Total Assets	[7]	112,600,000			112,600,000			78,000,000
Current Risk Management Liabilities	[7]	39,100,000			39,100,000			50,600,000
Long-term Risk Management Liabilities	[7]	5,500,000			5,500,000			1,400,000
Total Liabilities	[7]	44,600,000			44,600,000			52,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	68,000,000			68,000,000			26,000,000
Commodity [Member] | Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	500,000			500,000			500,000
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	500,000			500,000			500,000
Current Risk Management Liabilities	[7]	0			0			0
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	500,000			500,000			500,000
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	39,400,000			39,400,000			47,200,000
Long-term Risk Management Assets	[7]	3,700,000			3,700,000			1,600,000
Total Assets	[7]	43,100,000			43,100,000			48,800,000
Current Risk Management Liabilities	[7]	35,200,000			35,200,000			48,500,000
Long-term Risk Management Liabilities	[7]	3,200,000			3,200,000			900,000
Total Liabilities	[7]	38,400,000			38,400,000			49,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	4,700,000			4,700,000			(600,000)
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	600,000			600,000			600,000
Long-term Risk Management Assets	[7]	100,000			100,000			0
Total Assets	[7]	700,000			700,000			600,000
Current Risk Management Liabilities	[7]	5,400,000			5,400,000			6,400,000
Long-term Risk Management Liabilities	[7]	89,800,000			89,800,000			126,000,000
Total Liabilities	[7]	95,200,000			95,200,000			132,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(94,500,000)			(94,500,000)			(131,800,000)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	18,800,000			18,800,000			6,600,000
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	18,800,000			18,800,000			6,600,000
Current Risk Management Liabilities	[7]	900,000			900,000			200,000
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	900,000			900,000			200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	17,900,000			17,900,000			6,400,000
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	8,100,000			8,100,000			7,000,000
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	8,100,000			8,100,000			7,000,000
Current Risk Management Liabilities	[7]	1,800,000			1,800,000			800,000
Long-term Risk Management Liabilities	[7]	2,600,000			2,600,000			0
Total Liabilities	[7]	4,400,000			4,400,000			800,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	3,700,000			3,700,000			6,200,000
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	29,100,000			29,100,000			17,500,000
Long-term Risk Management Assets	[7]	10,600,000			10,600,000			6,300,000
Total Assets	[7]	39,700,000			39,700,000			23,800,000
Current Risk Management Liabilities	[7]	7,500,000			7,500,000			9,000,000
Long-term Risk Management Liabilities	[7]	55,400,000			55,400,000			58,300,000
Total Liabilities	[7]	62,900,000			62,900,000			67,300,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(23,200,000)			(23,200,000)			(43,500,000)
Interest Rate [Member]
Commodity:
Derivative, Notional Amount		500,000,000			500,000,000			500,000,000
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(12,700,000)			(12,700,000)			(13,000,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(800,000)			(800,000)
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		2,000,000			2,000,000			2,200,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					900,000			700,000
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		(4,600,000)			(4,600,000)			(4,500,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,100,000)			(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		(11,900,000)			(11,900,000)			(10,700,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,600,000)			(1,300,000)
Interest Rate [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		1,300,000			1,300,000			1,900,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					1,300,000			1,100,000
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		2,400,000			2,400,000			2,600,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					1,000,000			800,000
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		(3,700,000)			(3,700,000)			(6,000,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,500,000)			(1,400,000)
Interest Rate [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0			0			2,500,000
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	0			0			2,500,000
Current Risk Management Liabilities	[7]	500,000			500,000			0
Long-term Risk Management Liabilities	[7]	33,700,000			33,700,000			8,600,000
Total Liabilities	[7]	34,200,000			34,200,000			8,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(34,200,000)			(34,200,000)			(6,100,000)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		389,000,000			389,000,000			409,000,000
Long-term Risk Management Assets		305,900,000			305,900,000			307,200,000
Total Assets		694,900,000			694,900,000			716,200,000
Current Risk Management Liabilities		240,400,000			240,400,000			343,600,000
Long-term Risk Management Liabilities		329,100,000			329,100,000			347,500,000
Total Liabilities		569,500,000			569,500,000			691,100,000
Total MTM Derivative Contract Net Assets (Liabilities)		125,400,000			125,400,000			25,100,000
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(197,100,000)			(197,100,000)			(282,800,000)
Long-term Risk Management Assets	[8]	(41,000,000)			(41,000,000)			(25,100,000)
Total Assets	[8]	(238,100,000)			(238,100,000)			(307,900,000)
Current Risk Management Liabilities	[8]	(183,100,000)			(183,100,000)			(282,000,000)
Long-term Risk Management Liabilities	[8]	(41,900,000)			(41,900,000)			(25,500,000)
Total Liabilities	[8]	(225,000,000)			(225,000,000)			(307,500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(13,100,000)			(13,100,000)			(400,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(38,200,000)			(38,200,000)			(50,700,000)
Long-term Risk Management Assets	[8]	(4,600,000)			(4,600,000)			(1,300,000)
Total Assets	[8]	(42,800,000)			(42,800,000)			(52,000,000)
Current Risk Management Liabilities	[8]	(38,200,000)			(38,200,000)			(49,300,000)
Long-term Risk Management Liabilities	[8]	(4,800,000)			(4,800,000)			(1,200,000)
Total Liabilities	[8]	(43,000,000)			(43,000,000)			(50,500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	200,000			200,000			(1,500,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0			0			0
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	0			0			0
Current Risk Management Liabilities	[8]	0			0			0
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0			0			0
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(28,500,000)			(28,500,000)			(39,600,000)
Long-term Risk Management Assets	[8]	(2,800,000)			(2,800,000)			(900,000)
Total Assets	[8]	(31,300,000)			(31,300,000)			(40,500,000)
Current Risk Management Liabilities	[8]	(28,800,000)			(28,800,000)			(45,000,000)
Long-term Risk Management Liabilities	[8]	(2,800,000)			(2,800,000)			(800,000)
Total Liabilities	[8]	(31,600,000)			(31,600,000)			(45,800,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	300,000			300,000			5,300,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0			0			0
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	0			0			0
Current Risk Management Liabilities	[8]	0			0			0
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0			0			0
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(300,000)			(300,000)			(200,000)
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	(300,000)			(300,000)			(200,000)
Current Risk Management Liabilities	[8]	(300,000)			(300,000)			(200,000)
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	(300,000)			(300,000)			(200,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0			0			0
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(1,600,000)			(1,600,000)			(600,000)
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	(1,600,000)			(1,600,000)			(600,000)
Current Risk Management Liabilities	[8]	(1,600,000)			(1,600,000)			(600,000)
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	(1,600,000)			(1,600,000)			(600,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0			0			0
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	191,900,000			191,900,000			126,200,000
Long-term Risk Management Assets	[9]	264,900,000			264,900,000			282,100,000
Total Assets	[9]	456,800,000			456,800,000			408,300,000
Current Risk Management Liabilities	[9]	57,300,000			57,300,000			61,600,000
Long-term Risk Management Liabilities	[9]	287,200,000			287,200,000			322,000,000
Total Liabilities	[9]	344,500,000			344,500,000			383,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	112,300,000			112,300,000			24,700,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	68,400,000			68,400,000			24,900,000
Long-term Risk Management Assets	[9]	1,400,000			1,400,000			1,100,000
Total Assets	[9]	69,800,000			69,800,000			26,000,000
Current Risk Management Liabilities	[9]	900,000			900,000			1,300,000
Long-term Risk Management Liabilities	[9]	700,000			700,000			200,000
Total Liabilities	[9]	1,600,000			1,600,000			1,500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	68,200,000			68,200,000			24,500,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	500,000			500,000			500,000
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	500,000			500,000			500,000
Current Risk Management Liabilities	[9]	0			0			0
Long-term Risk Management Liabilities	[9]	0			0			0
Total Liabilities	[9]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	500,000			500,000			500,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	10,900,000			10,900,000			7,600,000
Long-term Risk Management Assets	[9]	900,000			900,000			700,000
Total Assets	[9]	11,800,000			11,800,000			8,300,000
Current Risk Management Liabilities	[9]	6,400,000			6,400,000			3,500,000
Long-term Risk Management Liabilities	[9]	400,000			400,000			100,000
Total Liabilities	[9]	6,800,000			6,800,000			3,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	5,000,000			5,000,000			4,700,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	600,000			600,000			600,000
Long-term Risk Management Assets	[9]	100,000			100,000			0
Total Assets	[9]	700,000			700,000			600,000
Current Risk Management Liabilities	[9]	5,400,000			5,400,000			6,400,000
Long-term Risk Management Liabilities	[9]	89,800,000			89,800,000			126,000,000
Total Liabilities	[9]	95,200,000			95,200,000			132,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(94,500,000)			(94,500,000)			(131,800,000)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	18,500,000			18,500,000			6,400,000
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	18,500,000			18,500,000			6,400,000
Current Risk Management Liabilities	[9]	600,000			600,000			0
Long-term Risk Management Liabilities	[9]	0			0			0
Total Liabilities	[9]	600,000			600,000			0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	17,900,000			17,900,000			6,400,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	6,500,000			6,500,000			6,400,000
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	6,500,000			6,500,000			6,400,000
Current Risk Management Liabilities	[9]	200,000			200,000			200,000
Long-term Risk Management Liabilities	[9]	2,600,000			2,600,000			0
Total Liabilities	[9]	2,800,000			2,800,000			200,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	$ 3,700,000			$ 3,700,000			$ 6,200,000
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		415.7			415.7			358.7
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		88.7			88.7			57.4
Power [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		0			0			0
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		52.8			52.8			38.5
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		8			8			10.4
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		19			19			10.3
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		13			13			22.7
Coal [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.2			0.2			2
Coal [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.2			0.2			2
Coal [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		84.4			84.4			53.7
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		8.4			8.4			1.1
Natural Gas [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		4.9			4.9			0.7
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		16.1			16.1			18.3
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		8.3			8.3			6.9
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.6			1.6			1.3
Heating Oil and Gasoline [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.7			1.7			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			1.6
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		$ 37,700,000			$ 37,700,000			$ 50,700,000
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | AEP Texas Inc. [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		(700,000)		900,000	(9,400,000)		7,000,000
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] | 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] | 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		19,300,000		17,700,000	31,700,000		38,500,000
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] | 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] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(500,000)		300,000	(1,300,000)		600,000
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] | 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)		600,000	(7,800,000)		6,300,000
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		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		(100,000)	100,000		0
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		300,000		1,000,000	8,300,000		4,900,000
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	7,300,000		1,600,000
Purchased Electricity for Resale [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
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		200,000	800,000		500,000
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		500,000		100,000	1,300,000		500,000
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		0	200,000		0
Other Operation Expense [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		100,000	300,000		100,000
Other Operation Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		0	200,000		0
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	300,000		100,000
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		0	200,000		0
Other Operation Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		0	200,000		0
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		600,000		100,000	1,500,000		400,000
Maintenance Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		100,000	300,000		100,000
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		100,000		100,000	300,000		100,000
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		0	200,000		0
Maintenance Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		100,000	300,000		100,000
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		0	200,000		0
Maintenance Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		0	200,000		0
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(14,000,000)		(8,800,000)	29,200,000		(26,800,000)
Regulatory Assets [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	0		100,000	0		0
Regulatory Assets [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	0		100,000	0		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	[10]	(3,500,000)		(800,000)	(300,000)		(1,000,000)
Regulatory Assets [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(9,300,000)		(8,700,000)	31,800,000		(25,900,000)
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(600,000)		0	(600,000)		0
Regulatory Assets [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(600,000)		300,000	(1,700,000)		100,000
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	33,800,000		15,600,000	206,200,000		81,800,000
Regulatory Liabilities [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	24,000,000		3,700,000	127,300,000		28,200,000
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	[10]	0		100,000	0		(200,000)
Regulatory Liabilities [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	0		2,100,000	11,700,000		15,300,000
Regulatory Liabilities [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	0		0	600,000		0
Regulatory Liabilities [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	3,900,000		2,600,000	34,800,000		13,700,000
Regulatory Liabilities [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	$ 1,500,000		$ 7,000,000	$ 7,600,000		$ 22,000,000
[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, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(2) million in 2018 and $(2) million in periods 2019-2021 and $3 million in periods 2022-2023; Level 3 matures $40 million in 2018, $122 million in periods 2019-2021, $21 million in periods 2022-2023 and $1 million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.
[5]	The December 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.
[6]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[7]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[9]	All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
[10]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended			12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017	Dec. 31, 2017
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 22,774		$ 22,774			$ 21,173.3
Long Term Debt, Fair Value		23,869.1		23,869.1			23,649.6
Other Temporary Investments
Cost		293.9		293.9			341.4
Gross Unrealized Gains		22.2		22.2			19.7
Gross Unrealized Losses		(2.8)		(2.8)			(1.4)
Other Short-term Investments		313.3		313.3			359.7
Debt and Equity Securities Within Other Temporary Investments
Proceeds from Investment Sales		0	$ 0	0		$ 0
Purchases of Investments		0.8	12.6	2.2		13.6
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		2,666		2,666			2,527.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,666		2,666			2,527.6
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		23,869.1		23,869.1			23,649.6
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				1,004.3			902.5
Other-Than-Temporary Impairments				(8)			(80.5)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		513.1	519.5	1,550.9		1,808.6
Purchases of Investments		521.2	525	1,589		1,842.2
Gross Realized Gains on Investment Sales		3.9	9.8	27.7		198.1
Gross Realized Losses on Investment Sales		3.5	5.2	22.2		145.4
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		348.7		348.7
After 1 year through 5 years		331.4		331.4
After 5 years through 10 years		177		177
After 10 years		157.7		157.7
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000		1,000			1,000
Adjusted Cost of Domestic Equity Securities		619		619			594
AEP Texas Inc. [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,914.4		3,914.4			3,649.3
Long Term Debt, Fair Value		4,019.2		4,019.2			3,964.8
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		4,019.2		4,019.2			3,964.8
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,872.6		2,872.6			2,550.4
Long Term Debt, Fair Value		2,861.1		2,861.1			2,782.9
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,861.1		2,861.1			2,782.9
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,061.7		4,061.7			3,980.1
Long Term Debt, Fair Value		4,629.8		4,629.8			4,782.6
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		4,629.8		4,629.8			4,782.6
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,062.4		3,062.4			2,745.1
Long Term Debt, Fair Value		3,161.9		3,161.9			3,014.7
Nuclear Trust Fund Investments
Fair Value		2,666		2,666			2,527.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,666		2,666			2,527.6
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		3,161.9		3,161.9			3,014.7
Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				1,004.3			902.5
Other-Than-Temporary Impairments				(8)			(80.5)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		513.1	519.5	1,550.9		1,808.6
Purchases of Investments		521.2	525	1,589		1,842.2
Gross Realized Gains on Investment Sales		3.9	9.8	27.7		198.1
Gross Realized Losses on Investment Sales		3.5	$ 5.2	22.2		$ 145.4
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		348.7		348.7
After 1 year through 5 years		331.4		331.4
After 5 years through 10 years		177		177
After 10 years		157.7		157.7
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000		1,000			1,000
Adjusted Cost of Domestic Equity Securities		619		619			594
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,716.3		1,716.3			1,719.3
Long Term Debt, Fair Value		1,941.9		1,941.9			2,064.3
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		1,941.9		1,941.9			2,064.3
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,286.9		1,286.9			1,286.5
Long Term Debt, Fair Value		1,373.4		1,373.4			1,457.1
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		1,373.4		1,373.4			1,457.1
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,072.7		3,072.7			2,441.9
Long Term Debt, Fair Value		3,068.4		3,068.4			2,645.9
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		3,068.4		3,068.4			2,645.9
Cash [Member]
Other Temporary Investments
Cost	[1]	170.4		170.4			220.1
Gross Unrealized Gains	[1]	0		0			0
Gross Unrealized Losses	[1]	0		0			0
Other Short-term Investments	[1],[2]	170.4		170.4			220.1
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,014.8		1,014.8			1,048.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,014.8		1,014.8			1,048.7
Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				13.8			34.3
Other-Than-Temporary Impairments				(8)			(5)
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		1,014.8		1,014.8			1,048.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,014.8		1,014.8			1,048.7
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				13.8			34.3
Other-Than-Temporary Impairments				(8)			(5)
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[3]	105.9		105.9			104.3
Gross Unrealized Gains	[3]	0		0			0
Gross Unrealized Losses	[3]	(2.8)		(2.8)			(1.4)
Other Short-term Investments	[3]	103.1		103.1			102.9
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[4]	1,609.6		1,609.6			1,461.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[4]	1,609.6		1,609.6			1,461.7
Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities				995.8
Nuclear Trust Fund Investments
Gross Unrealized Gains				990.5			868.2
Other-Than-Temporary Impairments				0	[5]		(75.5)
Fair Value Measurements (Textuals)
Unrealized Loss on Securities				5.3
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[4]	1,609.6		1,609.6			1,461.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[4]	1,609.6		1,609.6			1,461.7
Domestic [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				990.5			868.2
Other-Than-Temporary Impairments				0	[5]		(75.5)
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		17.6		17.6			17
Gross Unrealized Gains		22.2		22.2			19.7
Gross Unrealized Losses		0		0			0
Other Short-term Investments	[4]	39.8		39.8			36.7
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	41.6		41.6			17.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[6]	41.6		41.6			17.2
Cash and Cash Equivalents [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				0			0
Other-Than-Temporary Impairments				0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	41.6		41.6			17.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[6]	41.6		41.6			17.2
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				0			0
Other-Than-Temporary Impairments				0			0
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		951.9		951.9			981.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		951.9		951.9			981.2
US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				12.2			29.7
Other-Than-Temporary Impairments				(6.2)			(3.6)
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		951.9		951.9			981.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		951.9		951.9			981.2
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				12.2			29.7
Other-Than-Temporary Impairments				(6.2)			(3.6)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		54.4		54.4			58.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		54.4		54.4			58.7
Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				1.1			3.8
Other-Than-Temporary Impairments				(1.6)			(1.2)
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		54.4		54.4			58.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		54.4		54.4			58.7
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				1.1			3.8
Other-Than-Temporary Impairments				(1.6)			(1.2)
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		8.5		8.5			8.8
Contractual Maturities, Fair Value of Debt Securities
Fair Value		8.5		8.5			8.8
State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				0.5			0.8
Other-Than-Temporary Impairments				(0.2)			(0.2)
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		8.5		8.5			8.8
Contractual Maturities, Fair Value of Debt Securities
Fair Value		$ 8.5		8.5			8.8
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				0.5			0.8
Other-Than-Temporary Impairments				$ (0.2)			$ (0.2)
[1]	Primarily represents amounts held for the repayment of debt.
[2]	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[3]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[4]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[5]	Amount reported as Gross Unrealized Gains includes unrealized gains of $995.8 million and unrealized losses of $5.3 million. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.
[6]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Fair Value Assets and Liabiliti

Fair Value Assets and Liabilities (Details) $ in Millions		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2018USD ($)$ / MWh$ / MMBTU		Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)$ / MWh$ / MMBTU		Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)$ / MWh$ / MMBTU
Assets, Fair Value Disclosure
Other Short-term Investments		$ 313.3			$ 313.3			$ 359.7
Risk Management Assets
Risk Management Assets		456.8			456.8			408.3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,666			2,666			2,527.6
Total Assets		3,436.1			3,436.1			3,295.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities		344.5			344.5			383.6
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		172.3		$ 87.3	40.3		$ 2.5	2.5
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	19.9		19.8	150.9		37.4
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	1.5		14.8	9.5		37.2
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		10.4		(24.3)	16.4		(29.5)
Settlements		(56)		(49.2)	(212.3)		(49.7)
Transfers into Level 3	[3],[4]	2.3		5.7	16.5		16.1
Transfers out of Level 3	[4]	(1.2)		0.2	(2.5)		(9.1)
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	12		(9.3)	142.4		40.1
Ending Balance		161.2		45	$ 161.2		45	$ 40.3
Measurement Input, Counterparty Credit Risk [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value, Option, Relation to Measurement Inputs	[6]				0.001			0.0008
Measurement Input, Counterparty Credit Risk [Member] | High [Member]
Level 3 Quantitative Information
Fair Value, Option, Relation to Measurement Inputs	[6]				0.0418			0.0456
Measurement Input, Counterparty Credit Risk [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value, Option, Relation to Measurement Inputs	[6]				0.0158			0.018
Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		9.6			$ 9.6			$ 36.9
Risk Management Assets
Risk Management Assets		(210.1)			(210.1)			(285.4)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		14.4			14.4			9.7
Total Assets		(186.1)			(186.1)			(238.8)
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(197)			(197)			(285)
Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		303.7			303.7			322.8
Risk Management Assets
Risk Management Assets		1.7			1.7			3.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,636.8			1,636.8			1,469.2
Total Assets		1,942.2			1,942.2			1,795.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.9			1.9			5.1
Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Risk Management Assets
Risk Management Assets		291.8			291.8			411
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,014.8			1,014.8			1,048.7
Total Assets		1,306.6			1,306.6			1,459.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		327.4			327.4			425
Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0			0
Risk Management Assets
Risk Management Assets		373.4			373.4			278.8
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Total Assets		373.4			373.4			278.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		212.2			212.2			238.5
2018 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities								(1)
2018 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(2)			(2)			(3)
2018 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		40			40			59
2019 - 2021 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(2)			(2)
2019 - 2021 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		122			122			33
2022 - 2023 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		3			3			2
2022 - 2023 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		21			21			14
2024 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1			1			(29)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7]	421.1	[8]		421.1	[8]		383.8	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	251.4	[8]		251.4	[8]		309.5	[9]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(213.2)	[8]		(213.2)	[8]		(285.4)	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	(200.1)	[8]		(200.1)	[8]		(285)	[9]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	1.7	[8]		1.7	[8]		3.9	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	1.9	[8]		1.9	[8]		5.1	[9]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	270.9	[8]		270.9	[8]		391.2	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	271.4	[8]		271.4	[8]		392.5	[9]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	361.7	[8]		361.7	[8]		274.1	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	178.2	[8]		178.2	[8]		196.9	[9]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		251.5			251.5			225.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 202.4			$ 202.4			$ 233.7
Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(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 | $ / MWh	[10]	161.90			161.90			263
Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	33.54			33.54			36.32
Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 0			$ 0			$ 0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 2.8			$ 2.8			$ 0.2
Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[11]	2.19			2.19			2.37
Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[11]	2.97			2.97			2.96
Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[11]	2.45			2.45			2.62
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 121.9			$ 121.9			$ 53.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 7			$ 7			$ 4.6
FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(9.40)			(9.40)			(55.62)
FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	16.17			16.17			54.88
FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	0.83			0.83			0.41
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[7]	$ 35.7			$ 35.7			$ 22
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	58.9			58.9			65.5
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	3.1			3.1			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	3.1			3.1			0
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	0			0			0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	20.9			20.9			17.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	21.8			21.8			23.9
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	11.7			11.7			4.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	34			34			41.6
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets								2.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		34.2			34.2			8.6
Fair Value Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets								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
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0			0			0
Fair Value Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets								2.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		34.2			34.2			8.6
Fair Value Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets								0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0			0			0
AEP Texas Inc. [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		124.2			124.2			155.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		124.7			124.7			155.7
AEP Texas Inc. [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0			0			0
AEP Texas Inc. [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		124.2			124.2			155.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		124.2			124.2			155.2
AEP Texas Inc. [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.5			0.5			0.5
AEP Texas Inc. [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0			0			0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7]	0.5			0.5			0.5
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	0			0			0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	0			0			0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	0.5			0.5			0.5
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	0			0			0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		9.9			9.9			16.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		79.7			79.7			42.3
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		60		41.3	24.7		1.4	1.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	9		6.2	104.4		17.2
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	0		0
Settlements		(19.8)		(16.2)	(128.3)		(18.9)
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]	17.3		(1.9)	65.7		29.7
Ending Balance		66.5		29.4	66.5		29.4	24.7
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		(38.9)			(38.9)			(51.6)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		9.9			9.9			16.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		10.1			10.1			16.3
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		41.8			41.8			52.5
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0			0
Risk Management Assets
Risk Management Assets		66.7			66.7			25.1
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		66.7			66.7			25.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.2			0.2			0.4
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	69.8			69.8			26
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	1.6			1.6			1.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(38.9)			(38.9)			(51.6)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(39.1)			(39.1)			(50.1)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.2			0.2			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.3			0.3			0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	41.8			41.8			52.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	40.2			40.2			51.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	66.7			66.7			25.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.2			0.2			0.4
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1.8			1.8			0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1			$ 0.1			$ 0.4
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	14.98			14.98			20.52
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	59.45			59.45			195
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	36.30			36.30			33.80
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 64.9			$ 64.9			$ 24.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1			$ 0.1			$ 0
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	0.06			0.06			(0.36)
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	12.73			12.73			7.15
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	2.37			2.37			1.62
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,666			$ 2,666			$ 2,527.6
Total Assets		2,677.8			2,677.8			2,535.9
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		13.2		15.5	7.6		2.8	2.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	1.9		3.8	14.7		4
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	0		0
Settlements		(5.5)		(8.4)	(21.9)		(7.1)
Transfers into Level 3	[3],[4]	0		0	0		0
Transfers out of Level 3	[4]	0		0	(0.3)		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[5]	(0.2)		(0.7)	9.3		10.5
Ending Balance		9.4		10.2	9.4		10.2	7.6
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		14.4			14.4			9.7
Total Assets		(14.7)			(14.7)			(30.5)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,636.8			1,636.8			1,469.2
Total Assets		1,636.9			1,636.9			1,469.2
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,014.8			1,014.8			1,048.7
Total Assets		1,043.3			1,043.3			1,088.1
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		12.3			12.3			9.1
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Total Assets		12.3			12.3			9.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		2.9			2.9			1.5
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	11.8			11.8			8.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	6.8			6.8			3.6
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(29.1)			(29.1)			(40.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(29.4)			(29.4)			(45.5)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.1			0.1			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.1			0.1			0
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	28.5			28.5			39.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	33.2			33.2			47.6
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	12.3			12.3			9.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	2.9			2.9			1.5
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1.1			1.1			0.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.9			$ 0.9			$ 0.3
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	14.98			14.98			20.52
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	59.45			59.45			195
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	36.30			36.30			33.80
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 11.2			$ 11.2			$ 8.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 2			$ 2			$ 1.2
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(2.58)			(2.58)			(0.36)
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	6.21			6.21			5.75
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	0.73			0.73			0.86
Ohio Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		$ 15.2			$ 15.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15.9			15.9
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(86.9)		(130.5)	(132.4)		(119)	$ (119)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	0		(0.1)	1.3		(1)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	0		0
Settlements		0.6		1.2	3		5.1
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]	(8.9)		(9.1)	32.9		(23.6)
Ending Balance		(95.2)		(138.5)	$ (95.2)		(138.5)	$ (132.4)
Ohio Power Co [Member] | Measurement Input, Counterparty Credit Risk [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value, Option, Relation to Measurement Inputs	[6]				0.001			0.0008
Ohio Power Co [Member] | Measurement Input, Counterparty Credit Risk [Member] | High [Member]
Level 3 Quantitative Information
Fair Value, Option, Relation to Measurement Inputs	[6]				0.0188			0.019
Ohio Power Co [Member] | Measurement Input, Counterparty Credit Risk [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value, Option, Relation to Measurement Inputs	[6]				0.0141			0.0136
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			$ 0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0			0
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		15.2			15.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15.2			15.2
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.7			0.7
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
Risk Management Assets
Risk Management Assets		0			0			$ 0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		95.2			95.2			132.4
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.7			0.7			0.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	95.2			95.2			132.4
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.7			0.7			0.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	95.2			95.2			132.4
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		$ 95.2			$ 95.2			$ 132.4
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	27.23			27.23			30.52
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	64.61			64.61			170.43
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	43.26			43.26			44.62
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ 24.3		9.5	$ 6.2		0.7	$ 0.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	3.7		4	18.1		3.1
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	0		0
Settlements		(10.8)		(6.9)	(24.3)		(3.8)
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]	0.4		(1.9)	17.6		4.7
Ending Balance		17.6		4.7	17.6		4.7	6.2
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	18.5			18.5			6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.6			0.6			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(0.3)			(0.3)			(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(0.3)			(0.3)			(0.2)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.3			0.3			0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	18.5			18.5			6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.9			0.9			0.2
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		18.5			18.5			6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.9			$ 0.9			$ 0.2
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(9.40)			(9.40)			(6.62)
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	10.30			10.30			1.41
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(1.49)			(1.49)			(0.76)
Southwestern Electric Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ 4.9		12.4	$ 5.9		0.7	$ 0.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	1.7		3.8	(4.8)		6
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	0		0
Settlements		(2.7)		(7.6)	(1.3)		(6.8)
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]	(0.4)		4.5	3.7		13.2
Ending Balance		3.5		$ 13.1	3.5		$ 13.1	5.9
Southwestern Electric Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		7.9			7.9			6.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		4.4			4.4			0.8
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	6.5			6.5			6.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	2.8			2.8			0.2
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(1.6)			(1.6)			(0.6)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(1.6)			(1.6)			(0.6)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0			0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.2			0.2			0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0			0			0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	7.9			7.9			6.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	4.4			4.4			0.8
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		$ 2.8			$ 2.8			$ 0.2
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[11]	2.19			2.19			2.37
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[11]	2.97			2.97			2.96
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[11]	2.45			2.45			2.62
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 7.9			$ 7.9			$ 6.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 1.6			$ 1.6			$ 0.6
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(9.40)			(9.40)			(6.62)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	10.30			10.30			1.41
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[10]	(1.49)			(1.49)			(0.76)
Cash [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13],[14]	$ 170.4			$ 170.4			$ 220.1
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13]	9.6			9.6			36.9
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[13]	160.8			160.8			183.2
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		1,014.8			1,014.8			1,048.7
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		1,014.8			1,014.8			1,048.7
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		1,014.8			1,014.8			1,048.7
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			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		1,014.8			1,014.8			1,048.7
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	103.1			103.1			102.9
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		103.1			103.1			102.9
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	[16]	39.8			39.8			36.7
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[16]	0			0			0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[16]	39.8			39.8			36.7
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[16]	0			0			0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[16]	0			0			0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	41.6			41.6			17.2
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	14.4			14.4			9.7
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	27.2			27.2			7.5
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0			0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	41.6			41.6			17.2
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	14.4			14.4			9.7
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	27.2			27.2			7.5
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0			0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		951.9			951.9			981.2
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		951.9			951.9			981.2
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		951.9			951.9			981.2
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			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		951.9			951.9			981.2
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		54.4			54.4			58.7
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		54.4			54.4			58.7
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		54.4			54.4			58.7
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			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		54.4			54.4			58.7
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		8.5			8.5			8.8
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		8.5			8.5			8.8
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		8.5			8.5			8.8
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			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		8.5			8.5			8.8
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,609.6			1,609.6			1,461.7
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,609.6			1,609.6			1,461.7
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,609.6			1,609.6			1,461.7
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	1,609.6			1,609.6			1,461.7
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	$ 0			$ 0			$ 0
[1]	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 liabilities/assets or accounts payable.
[6]	Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[7]	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.’’
[8]	The September 30, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(2) million in 2018 and $(2) million in periods 2019-2021 and $3 million in periods 2022-2023; Level 3 matures $40 million in 2018, $122 million in periods 2019-2021, $21 million in periods 2022-2023 and $1 million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.
[9]	The December 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.
[10]	Represents market prices in dollars per MWh.
[11]	Represents market prices in dollars per MMBtu.
[12]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[13]	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[14]	Primarily represents amounts held for the repayment of debt.
[15]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[16]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[17]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017		Sep. 30, 2018		Sep. 30, 2017
Income Tax Expense (Benefit)		$ 80.7		$ (264)		$ (93.5)		$ (797.8)
Increase in Current Liabilities						101.1		(260.3)
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 141.9		$ 205.7
Effective Income Tax Rate		(16.20%)		33.00%		5.60%		35.30%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Kentucky Net Operating Loss Limitation Percent		80.00%
Kentucky Single Corporate Tax Rate		5.00%
Net Regulatory Liability for Tax Reform [Member]
Income Taxes (Textuals)
Excess Accumulated Deferred Income Taxes						$ 4,300
Incremental Liability for Tax Reform [Member]
Income Taxes (Textuals)
Excess Accumulated Deferred Income Taxes						1,100
Pretax Excess ADIT [Member]
Income Taxes (Textuals)
Excess Accumulated Deferred Income Taxes						4,300
Temporary Differences Associated with Depreciable Property [Member]
Income Taxes (Textuals)
Excess Accumulated Deferred Income Taxes						3,400
Remaining Excess ADIT [Member]
Income Taxes (Textuals)
Excess Accumulated Deferred Income Taxes						900
AEP Texas Inc. [Member]
Income Tax Expense (Benefit)		$ (8.3)		$ (30.6)		(26.4)		$ (74.2)
Increase in Current Liabilities						14.1		(31.2)
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 67.1		$ 7.4
Effective Income Tax Rate		12.60%		32.20%		14.90%		33.60%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
AEP Transmission Co [Member]
Income Tax Expense (Benefit)		$ (17.6)		$ (29.5)	[1]	$ (63.7)	[1]	$ (108.2)	[1]
Increase in Current Liabilities						(28)		0.5
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 18		$ 25.7
Effective Income Tax Rate	[2]	18.40%		33.50%		20.70%		33.80%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Kentucky Net Operating Loss Limitation Percent		80.00%
Kentucky Single Corporate Tax Rate		5.00%
Appalachian Power Co [Member]
Income Tax Expense (Benefit)		$ 78.9		$ (43.2)		$ 35.1		$ (136.7)
Increase in Current Liabilities						64.1		9.1
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 3.8		$ 7.9
Effective Income Tax Rate		(962.20%)		33.40%		(13.80%)		35.50%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Indiana Michigan Power Co [Member]
Income Tax Expense (Benefit)		$ (13.7)		$ (28.6)		$ (26.8)		$ (61.8)
Increase in Current Liabilities						0.3		(14.2)
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 46.3		$ 40.9
Effective Income Tax Rate		15.90%		30.60%		10.40%		30.10%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Kentucky Net Operating Loss Limitation Percent		80.00%
Kentucky Single Corporate Tax Rate		5.00%
Ohio Power Co [Member]
Income Tax Expense (Benefit)		$ 28.1		$ (48.3)		$ (11.4)		$ (128)
Increase in Current Liabilities						(4.3)		(34.8)
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 62.5		$ 43.4
Effective Income Tax Rate		(46.40%)		36.90%		4.60%		35.60%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Kentucky Net Operating Loss Limitation Percent		80.00%
Kentucky Single Corporate Tax Rate		5.00%
Public Service Co Of Oklahoma [Member]
Income Tax Expense (Benefit)		$ (3.6)		$ (27.4)		$ (8.6)		$ (42.6)
Increase in Current Liabilities						15.1		1.5
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 10.9		$ (1.4)
Effective Income Tax Rate		5.60%		37.20%		8.70%		37.40%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Southwestern Electric Power Co [Member]
Income Tax Expense (Benefit)		$ (9.6)		$ (22.5)		$ (17.9)		$ (45.2)
Increase in Current Liabilities						15.6		(14.6)
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 52.1		$ (5.2)
Effective Income Tax Rate		9.80%		21.20%		11.40%		25.70%
Income Taxes (Textuals)
Federal Statutory Income Tax Rate		21.00%		35.00%		21.00%		35.00%
Reduction in Corporate Federal Income Tax Rate [Member]
Increase in Current Liabilities						$ 51.1
Increase in Deferred Credits and Other Noncurrent Liabilities						98.4
Reduction in Corporate Federal Income Tax Rate [Member] | AEP Texas Inc. [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						21.9
Reduction in Corporate Federal Income Tax Rate [Member] | AEP Transmission Co [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						8.6
Reduction in Corporate Federal Income Tax Rate [Member] | Appalachian Power Co [Member]
Increase in Current Liabilities						40.5
Increase in Deferred Credits and Other Noncurrent Liabilities						3.7
Reduction in Corporate Federal Income Tax Rate [Member] | Indiana Michigan Power Co [Member]
Increase in Current Liabilities						2
Increase in Deferred Credits and Other Noncurrent Liabilities						12.8
Reduction in Corporate Federal Income Tax Rate [Member] | Ohio Power Co [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						20.8
Reduction in Corporate Federal Income Tax Rate [Member] | Public Service Co Of Oklahoma [Member]
Increase in Current Liabilities						2.4
Increase in Deferred Credits and Other Noncurrent Liabilities						2.3
Reduction in Corporate Federal Income Tax Rate [Member] | Southwestern Electric Power Co [Member]
Increase in Current Liabilities						5.3
Increase in Deferred Credits and Other Noncurrent Liabilities						27.6
Excess ADIT [Member]
Increase in Current Liabilities						15.3
Increase in Deferred Credits and Other Noncurrent Liabilities						20.6
Excess ADIT [Member] | AEP Texas Inc. [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						6.9
Excess ADIT [Member] | AEP Transmission Co [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						0.1
Excess ADIT [Member] | Appalachian Power Co [Member]
Increase in Current Liabilities						9.5
Increase in Deferred Credits and Other Noncurrent Liabilities						0.7
Excess ADIT [Member] | Indiana Michigan Power Co [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						1.4
Excess ADIT [Member] | Ohio Power Co [Member]
Increase in Current Liabilities						0
Increase in Deferred Credits and Other Noncurrent Liabilities						3.3
Excess ADIT [Member] | Public Service Co Of Oklahoma [Member]
Increase in Current Liabilities						4.7
Increase in Deferred Credits and Other Noncurrent Liabilities						0
Excess ADIT [Member] | Southwestern Electric Power Co [Member]
Increase in Current Liabilities						1.2
Increase in Deferred Credits and Other Noncurrent Liabilities						$ 7.8
Amortization of Excess ADIT [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(7.40%)				(4.70%)
Amortization of Excess ADIT [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(31.70%)				(4.90%)
Amortization of Excess ADIT [Member] | Ohio Power Co [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(4.10%)				(2.50%)
Amortization of Excess ADIT [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(17.30%)				(13.90%)
Amortization of Excess ADIT [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(9.00%)				(7.90%)
Kentucky Legislation - House Bill 487 [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent						(1.10%)
IRS Audit Settlement [Member]
Reversed Unrecognized Tax Benefit			$ 72
Remeasurement of Kentucky Deferred Taxes [Member]
Income Tax Expense (Benefit)			$ 18
West Virginia Tax Reform [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(17.90%)				(5.40%)
West Virginia Tax Reform [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(887.80%)				(28.60%)
Ohio Tax Reform [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(7.80%)				(2.30%)
Ohio Tax Reform [Member] | Ohio Power Co [Member]
Income Taxes (Textuals)
Effective Income Tax Rate Reconciliation, Variance Explanation, Percent		(62.00%)				(15.10%)
[1]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[2]	The 2017 ETRs presented above reflect the revisions made to AEPTCo's previously issued financial statements. See Note 1 - Significant Accounting Matters for additional information.

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
		Oct. 25, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Long-term Debt
Senior Unsecured Notes			$ 18,342.1		$ 18,342.1		$ 16,478.3
Pollution Control Bonds			1,643.2		1,643.2		1,621.7
Notes Payable			233.2		233.2		260.8
Securitization Bonds			1,145.2		1,145.2		1,416.5
Spent Nuclear Fuel Obligation	[1]		272.1		272.1		268.6
Other Long-term Debt			1,138.2		1,138.2		1,127.4
Total Long-term Debt Outstanding			22,774		22,774		21,173.3
Long-term Debt Due Within One Year			1,904.2		1,904.2		1,753.7
Long-term Debt			20,869.8		20,869.8		19,419.6
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				3,612.6
Retirements and Principal Payments					1,959.5	$ 2,427.2
Short-term Debt:
Securitized Debt for Receivables	[3]		750		750		718
Commercial Paper			1,473.2		1,473.2		898.6
Notes Payable			19.4		19.4		22
Total Short-term Debt			$ 2,242.6		$ 2,242.6		$ 1,638.6
Securitized Debt for Receivables	[3],[4]		2.06%		2.06%		1.22%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable			2.27%	1.33%	2.06%	1.17%
Net Uncollectible Accounts Receivable Written Off			$ 9.6	$ 7	$ 19	$ 18.2
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts			1,082.9		1,082.9		$ 925.5
Total Principal Outstanding			750		750		718
Delinquent Securitized Accounts Receivable			58.2		58.2		41.1
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable			29.3		29.3		28.7
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable			242.1		242.1		303.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			4,333.1	4,104.7	12,394.6	11,614.5
Financing Activities (Textuals)
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			316		316		$ 312
Repayments of Long-term Debt					1,959.5	2,427.2
Reacquired Pollution Controls Bonds Held by Trustees			574		$ 574
Maximum Percentage Debt to Capitalization					67.50%
Total Commitment from Bank Conduits to Finance Receivables			$ 750		$ 750
Commercial Paper [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		2.40%		2.40%		1.85%
Loans Payable [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		3.45%		3.45%		2.92%
AEP Texas Inc. [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,914.4		$ 3,914.4		$ 3,649.3
Long-term Debt Due Within One Year			500.5		500.5		266.1
Long-term Debt			3,413.9		3,413.9		3,383.2
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					231.7	248.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			407.3
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 231.7	$ 248.4
Maximum Percentage Debt to Capitalization					67.50%
AEP Texas Inc. [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 390.6
Maximum Loans to Money Pool					106.9
Average Borrowings from Money Pool					189.9
Average Loans to Money Pool					47.1
Net Loans (Borrowings) to/from Money Pool			(77.8)		(77.8)
Authorized Short Term Borrowing Limit					$ 500
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.25%	1.29%
Average Interest Rate For Funds Loaned					2.29%	1.35%
AEP Texas Inc. [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Loans to Money Pool					$ 8.4
Average Loans to Money Pool					8.1
Net Loans (Borrowings) to/from Money Pool			$ 8		$ 8
Maximum and Minimum Interest Rates
Maximum Interest Rate For Funds Loaned					2.52%	1.49%
Minimum Interest Rate for Funds Loaned					1.83%	0.00%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Loaned					2.26%	1.27%
AEP Texas Inc. [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 70
Interest Rate (Percentage)			5.17%		5.17%
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 70
AEP Texas Inc. [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 27.6
Interest Rate (Percentage)			1.976%		1.976%
Due Date					2,020
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 27.6
AEP Texas Inc. [Member] | Securitization Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 104.1
Interest Rate (Percentage)			5.306%		5.306%
Due Date					2,020
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 104.1
AEP Texas Inc. [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 500
Interest Rate (Percentage)			3.95%		3.95%
Due Date					2,028
AEP Texas Inc. [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 30
Interest Rate (Percentage)			5.89%		5.89%
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 30
AEP Transmission Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,872.6		2,872.6		2,550.4
Long-term Debt Due Within One Year			50		50		50
Long-term Debt			2,822.6		2,822.6		2,500.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	[5]		206.8
Financing Activities (Textuals)
Sub-Limit of Secured Debt			$ 50		$ 50
Maximum Percentage of Consolidated Tangible Net Assets			10.00%		10.00%
Maximum Percentage Debt to Capitalization					67.50%
AEP Transmission Co [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 371.3
Maximum Loans to Money Pool					232.7
Average Borrowings from Money Pool					237.9
Average Loans to Money Pool					28.1
Net Loans (Borrowings) to/from Money Pool			$ 232.7		232.7
Authorized Short Term Borrowing Limit	[6]				$ 795
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.26%	1.36%
Average Interest Rate For Funds Loaned					2.04%	1.04%
AEP Transmission Co [Member] | Direct Borrowing [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 1.1
Maximum Loans to Money Pool					104.7
Average Borrowings from Money Pool					1.1
Average Loans to Money Pool					50
Borrowings from Parent			1.1		1.1
Loans to Parent			$ 45.3		45.3
Authorized Short Term Borrowing Limit	[7]				$ 75
Maximum and Minimum Interest Rates
Maximum Interest Rate for Funds Borrowed					2.52%	1.49%
Minimum Interest Rate For Funds Borrowed					1.76%	0.92%
Maximum Interest Rate For Funds Loaned					2.52%	1.49%
Minimum Interest Rate for Funds Loaned					1.76%	0.92%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.26%	1.27%
Average Interest Rate For Funds Loaned					2.27%	1.31%
AEP Transmission Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 325
Interest Rate (Percentage)			4.25%		4.25%
Due Date					2,048
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 4,061.7		$ 4,061.7		3,980.1
Long-term Debt Due Within One Year			430.7		430.7		249.2
Long-term Debt			3,631		3,631		3,730.9
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					24	$ 377.9
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			122.9		122.9		136.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			764.1
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			334.1	335.5	1,079.2	1,029.4
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 24	377.9
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			1.8	1.5	$ 5.1	$ 4.2
Appalachian Power Co [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 295.5
Maximum Loans to Money Pool					23.7
Average Borrowings from Money Pool					185.3
Average Loans to Money Pool					23.4
Net Loans (Borrowings) to/from Money Pool			$ (75.4)		(75.4)
Authorized Short Term Borrowing Limit					$ 600
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.22%	1.24%
Average Interest Rate For Funds Loaned					2.19%	1.28%
Appalachian Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 104.4
Interest Rate (Percentage)			2.625%		2.625%
Due Date					2,022
Appalachian Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 24
Interest Rate (Percentage)			2.008%		2.008%
Due Date					2,023
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 24
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,062.4		3,062.4		2,745.1
Long-term Debt Due Within One Year			172.7		172.7		474.7
Long-term Debt			2,889.7		2,889.7		2,270.4
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					856.1	$ 227.1
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			169.5		169.5		136.5
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			619.5
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			498.4	409.9	1,401.7	1,218.9
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 856.1	227.1
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			2.5	1.8	$ 6.8	$ 4.9
Indiana Michigan Power Co [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 322.1
Maximum Loans to Money Pool					657.8
Average Borrowings from Money Pool					257.6
Average Loans to Money Pool					116.4
Net Loans (Borrowings) to/from Money Pool			$ 72.5		72.5
Authorized Short Term Borrowing Limit					$ 500
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.16%	1.24%
Average Interest Rate For Funds Loaned					2.06%	1.27%
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 55.5
Interest Rate (Variable)					Variable
Due Date					2,022
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 3.5
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 3.5
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 10.1
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 10.1
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 18.8
Interest Rate (Variable)					Variable
Due Date					2,020
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 18.8
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 19.5
Interest Rate (Variable)					Variable
Due Date					2,021
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 19.5
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables Six [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 21.3
Interest Rate (Variable)					Variable
Due Date					2,022
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 21.3
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Seven [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 6.7
Interest Rate (Variable)					Variable
Due Date					2,022
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 6.7
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Eight [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 4
Financing Activities (Textuals)
Repayments of Long-term Debt		$ 4
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 200
Interest Rate (Variable)					Variable
Due Date					2,021
Indiana Michigan Power Co [Member] | Other Long Term Debt Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 200
Interest Rate (Variable)					Variable
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 200
Indiana Michigan Power Co [Member] | Other Long Term Debt Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 1.2
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,025
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 1.2
Indiana Michigan Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 100
Interest Rate (Percentage)			3.05%		3.05%
Due Date					2,025
Indiana Michigan Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 100
Interest Rate (Percentage)			1.75%		1.75%
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 100
Indiana Michigan Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 350
Interest Rate (Percentage)			3.85%		3.85%
Due Date					2,028
Indiana Michigan Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 475
Interest Rate (Percentage)			4.25%		4.25%
Due Date					2,048
Indiana Michigan Power Co [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 475
Interest Rate (Percentage)			7.00%		7.00%
Due Date					2,019
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 475
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,716.3		1,716.3		1,719.3
Long-term Debt Due Within One Year			47.8		47.8		397
Long-term Debt			1,668.5		1,668.5		1,322.3
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					397	$ 46.4
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			413.7		413.7		367.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			740.9
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			695.2	616.3	2,046.9	1,741.7
Financing Activities (Textuals)
Repayments of Long-term Debt					397	46.4
Reacquired Pollution Controls Bonds Held by Trustees			345		345
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			7.2	6.1	$ 18.8	$ 16.5
Ohio Power Co [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 270.8
Maximum Loans to Money Pool					225
Average Borrowings from Money Pool					169
Average Loans to Money Pool					189.4
Net Loans (Borrowings) to/from Money Pool			$ (242.9)		(242.9)
Authorized Short Term Borrowing Limit					$ 500
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.18%	1.40%
Average Interest Rate For Funds Loaned					2.47%	0.98%
Ohio Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.1
Interest Rate (Percentage)			1.149%		1.149%
Due Date					2,028
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 0.1
Ohio Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 46.9
Interest Rate (Percentage)			2.049%		2.049%
Due Date					2,019
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 46.9
Ohio Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 400
Interest Rate (Percentage)			4.15%		4.15%
Due Date					2,048
Ohio Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 350
Interest Rate (Percentage)			6.05%		6.05%
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 350
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,286.9		1,286.9		1,286.5
Long-term Debt Due Within One Year			0.5		0.5		0.5
Long-term Debt			1,286.4		1,286.4		1,286
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					0.3	$ 0.3
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			163		163		115.1
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			479.1
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			454.9	407	1,171.2	1,022.6
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 0.3	0.3
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			2.3	2	$ 6	$ 5.2
Public Service Co Of Oklahoma [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 193.7
Maximum Loans to Money Pool					30.9
Average Borrowings from Money Pool					119.8
Average Loans to Money Pool					10.1
Net Loans (Borrowings) to/from Money Pool			$ (22)		(22)
Authorized Short Term Borrowing Limit					$ 300
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.25%	1.30%
Average Interest Rate For Funds Loaned					1.86%	0.00%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.3
Interest Rate (Percentage)			3.00%		3.00%
Due Date					2,027
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 0.3
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,072.7		3,072.7		2,441.9
Long-term Debt Due Within One Year			457.2		457.2		3.7
Long-term Debt			2,615.5		2,615.5		2,438.2
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					385.3	$ 353.6
Short-term Debt:
Notes Payable			19.4		19.4		22
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			190.5		190.5		$ 138.2
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			535.6
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			512.6	455	1,364.6	1,200.8
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 385.3	353.6
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			2.6	$ 2	$ 6.6	$ 5.4
Southwestern Electric Power Co [Member] | Utility [Member]
Maximum Interest Rate					2.52%	1.49%
Minimum Interest Rate					1.81%	0.92%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 200.1
Maximum Loans to Money Pool					525.5
Average Borrowings from Money Pool					143.2
Average Loans to Money Pool					343.3
Net Loans (Borrowings) to/from Money Pool			516.6		516.6
Authorized Short Term Borrowing Limit					$ 350
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.31%	1.26%
Average Interest Rate For Funds Loaned					1.87%	0.98%
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Loans to Money Pool					$ 2
Average Loans to Money Pool					2
Net Loans (Borrowings) to/from Money Pool			$ 2		$ 2
Maximum and Minimum Interest Rates
Maximum Interest Rate For Funds Loaned					2.52%	1.49%
Minimum Interest Rate for Funds Loaned					1.83%	0.00%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Loaned					2.26%	1.27%
Southwestern Electric Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 3.2
Interest Rate (Percentage)			4.58%		4.58%
Due Date					2,032
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 3.2
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.2
Interest Rate (Percentage)			3.50%		3.50%
Due Date					2,023
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 0.2
Southwestern Electric Power Co [Member] | Other Long Term Debt Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.2
Interest Rate (Percentage)			4.28%		4.28%
Due Date					2,023
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 0.2
Southwestern Electric Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 81.7
Interest Rate (Percentage)			4.95%		4.95%
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 81.7
Southwestern Electric Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 575
Interest Rate (Percentage)			4.10%		4.10%
Due Date					2,028
Southwestern Electric Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 450
Interest Rate (Percentage)			3.85%		3.85%
Due Date					2,048
Southwestern Electric Power Co [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 300
Interest Rate (Percentage)			5.875%		5.875%
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 300
Southwestern Electric Power Co [Member] | Loans Payable [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		3.45%		3.45%		2.92%
AEP Energy [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.1
Interest Rate (Percentage)			5.75%		5.75%
Due Date					2,019
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 0.1
Transource Energy [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 12.7
Interest Rate (Variable)					Variable
Due Date					2,020
Wheeling Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 65
Interest Rate (Percentage)			3.00%		3.00%
Due Date					2,022
Wheeling Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 65
Interest Rate (Variable)					Variable
Due Date					2,018
Financing Activities (Textuals)
Repayments of Long-term Debt					$ 65
July 2020 [Member]
Financing Activities (Textuals)
Commitment From Bank Conduits To Finance Receivables			$ 125		125
July 2021 [Member]
Financing Activities (Textuals)
Commitment From Bank Conduits To Finance Receivables			$ 625		$ 625
[1]	Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $316 million and $312 million as of September 30, 2018 and December 31, 2017, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
[2]	Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
[3]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[4]	Weighted average rate.
[5]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[6]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
[7]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Variable Interest Entities (Textuals) [Abstract]
Redeemable Noncontrolling Interest		$ 70	$ 0
Trent and Desert Sky Wind Farms [Member]
Variable Interest Entities (Textuals) [Abstract]
Non-Affiliate Interest		20.10%
AEP Ownership in LLCs		79.90%
Desert Sky and Trent PPA Period	12 years
Redeemable Noncontrolling Interest		$ 70
Current Assets [Member] | Trent and Desert Sky Wind Farms [Member]
Assets [Abstract]
Assets		89.2
Net Property Plant And Equipment [Member] | Trent and Desert Sky Wind Farms [Member]
Assets [Abstract]
Assets		350.8
Net Property Plant And Equipment [Member] | Non-Affiliate Contribution [Member]
Assets [Abstract]
Assets		84
Other Noncurrent Assets [Member] | Trent and Desert Sky Wind Farms [Member]
Assets [Abstract]
Assets		0.4
Total Assets [Member] | Trent and Desert Sky Wind Farms [Member]
Assets [Abstract]
Assets		440.4
Current Liabilities [Member] | Trent and Desert Sky Wind Farms [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity		93.4
Noncurrent Liabilities [Member] | Trent and Desert Sky Wind Farms [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity		6.1
Equity [Member] | Trent and Desert Sky Wind Farms [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity		340.9
Total Liabilities And Equity [Member] | Trent and Desert Sky Wind Farms [Member]
Liabilities and Equity [Abstract]
Variable Interest Carrying Amount Liabilities and Equity		$ 440.4

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2018		Sep. 30, 2017		Dec. 31, 2017
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		$ 4,333.1		$ 4,104.7		$ 12,394.6		$ 11,614.5
Total Revenues		4,333.1		4,104.7		12,394.6		11,614.5
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		1,018.6				1,018.6
Revenue Textuals [Abstract]
Revenue from Related Parties		0		0		0		0
2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		246.1				246.1
2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		258.7				258.7
2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		164.8				164.8
2022 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		349				349
Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3,372				9,464.7
Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,660.9				4,617.9
Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		955.2				2,656.5
Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		697.1				2,022
Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		58.8				168.3
Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		760.5				2,579.1
Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		240.8	[1]			944.7	[2]
Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		120.6	[3]			594.2	[4]
Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		399.1				1,040.2
Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		194.6	[5]			379.6	[6]
Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		4,327.1				12,423.4
Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		6				(28.8)
Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		55.5		59.7		212.9		165.7
Total Revenues		58.6	[5]			78.5	[6]
Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(52.6)	[7]			(107.3)	[8]
AEP Texas Inc. [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		407.3
Total Revenues		433.4		431.2		1,193.3		1,164.3
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		74.2				74.2
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		14.3				14.3				$ 12.3
Revenue Textuals [Abstract]
Revenue from Related Parties		27.5		18.9		63.3		50.8
AEP Texas Inc. [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		74.2				74.2
AEP Texas Inc. [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Texas Inc. [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Texas Inc. [Member] | 2022 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		326.2				880.9
AEP Texas Inc. [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		178.8				453.6
AEP Texas Inc. [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		113.7				328.5
AEP Texas Inc. [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		27.2				79.7
AEP Texas Inc. [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		6.5				19.1
AEP Texas Inc. [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		73.6				229.6
AEP Texas Inc. [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[9]			0	[10]
AEP Texas Inc. [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		73.6	[11]			229.6	[12]
AEP Texas Inc. [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		7.5	[13]			21.8	[14]
AEP Texas Inc. [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers						1,132.3
AEP Texas Inc. [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		26.1				61
AEP Texas Inc. [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.4		0.8		3		2.1
Total Revenues		27.1	[15]			62.1	[16]
AEP Texas Inc. [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(1)	[17]			(1.1)	[18]
AEP Transmission Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	206.8
Total Revenues		194.4	[19]	165.6	[20]	586.2	[19],[20]	534.8	[20]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		166.8				166.8
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		73				73				93.2
Revenue Textuals [Abstract]
Revenue from Related Parties		148.4		130.1	[20]	453.8	[20]	439.1	[20]
AEP Transmission Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		71.9				71.9				47.1
AEP Transmission Co [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		166.8				166.8
AEP Transmission Co [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Transmission Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
AEP Transmission Co [Member] | 2022 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	[19]	0				0
AEP Transmission Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	0				0
AEP Transmission Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	0				0
AEP Transmission Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	0				0
AEP Transmission Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	0				0
AEP Transmission Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	206.6				612.9
AEP Transmission Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	0	[9]			0	[10]
AEP Transmission Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	206.6	[11]			612.9	[12]
Revenue Textuals [Abstract]
Revenue from Related Parties		146				448
AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]	0.2	[13]			8.7	[14]
AEP Transmission Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[19]					621.6
AEP Transmission Co [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues	[19]	(12.4)				(35.4)
AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		(0.1)	[20]	0.1	[20]	0	[20]
Total Revenues	[19]	0	[15]			0	[16]
AEP Transmission Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues	[19]	(12.4)	[17]			(35.4)	[18]
Revenue Textuals [Abstract]
Revenue from Related Parties		48				48
Appalachian Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		764.1
Total Revenues		762		719.3		2,249.4		2,187.4
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		100.7				100.7
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		70.6				70.6				69.3
Revenue Textuals [Abstract]
Revenue from Related Parties		42.9		41.9		138.7		130.6
Appalachian Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		54.1				54.1				35.6
Appalachian Power Co [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		30.7				30.7
Appalachian Power Co [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		32.9				32.9
Appalachian Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		25.5				25.5
Appalachian Power Co [Member] | 2022 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		652.8				1,974.5
Appalachian Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		320.9				1,017.2
Appalachian Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		155.6				443.8
Appalachian Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		157.1				455.9
Appalachian Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		19.2				57.6
Appalachian Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		95.4				254.3
Appalachian Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		74.5	[9]			194.1	[10]
Revenue Textuals [Abstract]
Revenue from Related Parties		30				100
Appalachian Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		20.9	[11]			60.2	[12]
Appalachian Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		15.9	[13]			42.2	[14]
Appalachian Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers						2,271
Appalachian Power Co [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(2.1)				(21.6)
Appalachian Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.3		3		7.6		11.8
Total Revenues		(0.9)	[15]			(0.9)	[16]
Appalachian Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(1.2)	[17]			(20.7)	[18]
Indiana Michigan Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		619.5
Total Revenues		629.7		557.7		1,796.2		1,585.5
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		13.6				13.6
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		51.7				51.7				50
Indiana Michigan Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		24.7				24.7				15.1
Indiana Michigan Power Co [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		6.3				6.3
Indiana Michigan Power Co [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		3				3
Indiana Michigan Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		2.9				2.9
Indiana Michigan Power Co [Member] | 2022 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		1.4				1.4
Indiana Michigan Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		497.3				1,362.6
Indiana Michigan Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		207.4				559.4
Indiana Michigan Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		139.5				373.7
Indiana Michigan Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		148.7				424.1
Indiana Michigan Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.7				5.4
Indiana Michigan Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		99.8				366.6
Indiana Michigan Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		93.6	[9]			349.7	[10]
Indiana Michigan Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		6.2	[11]			16.9	[12]
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		22.4	[13]			71	[14]
Indiana Michigan Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers						1,800.2
Indiana Michigan Power Co [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		10.2				(4)
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.7		3.6		10.1		9.9
Total Revenues		8.7	[15]			0	[16]
Revenue Textuals [Abstract]
Revenue from Related Parties		17				57
Indiana Michigan Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		1.5	[17]			(4)	[18]
Ohio Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		740.9
Total Revenues		778.3		742		2,318		2,152
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		33.9				33.9
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		72.4				72.4				70.2
Revenue Textuals [Abstract]
Revenue from Related Parties		3.3		4.6		17.9		19.4
Ohio Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		42.5				42.5				26.1
Ohio Power Co [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		21.5				21.5
Ohio Power Co [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		12.4				12.4
Ohio Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Ohio Power Co [Member] | 2022 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		756				2,188.8
Ohio Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		433.5				1,258.4
Ohio Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		222.9				632.8
Ohio Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		96.3				287.8
Ohio Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3.3				9.8
Ohio Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		14.8				42.8
Ohio Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[9]			0	[10]
Ohio Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		14.8	[11]			42.8	[12]
Ohio Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(29.9)	[13]			51.3	[14]
Ohio Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers						2,282.9
Ohio Power Co [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		37.4				35.1
Ohio Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.4		1.4		5.3		4.8
Total Revenues		74.3	[15]			82.3	[16]
Ohio Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(36.9)	[17]			(47.2)	[18]
Revenue Textuals [Abstract]
Revenue from Related Parties		48				48
Public Service Co Of Oklahoma [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		479.1
Total Revenues		481.4		442.8		1,216.5		1,091.6
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		4.5				4.5
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		39.8				39.8				32.9
Revenue Textuals [Abstract]
Revenue from Related Parties		1.1		1.1		3.7		3.2
Public Service Co Of Oklahoma [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		17.1				17.1				6.1
Public Service Co Of Oklahoma [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		4.5				4.5
Public Service Co Of Oklahoma [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Public Service Co Of Oklahoma [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Public Service Co Of Oklahoma [Member] | 2022 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		447.6				1,134.6
Public Service Co Of Oklahoma [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		220.8				531.4
Public Service Co Of Oklahoma [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		122.2				317.9
Public Service Co Of Oklahoma [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		80.2				220.4
Public Service Co Of Oklahoma [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		24.4				64.9
Public Service Co Of Oklahoma [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		26				56.1
Public Service Co Of Oklahoma [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		12.5	[9]			26.7	[10]
Public Service Co Of Oklahoma [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		13.5	[11]			29.4	[12]
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		5.5	[13]			14.6	[14]
Public Service Co Of Oklahoma [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers						1,205.3
Public Service Co Of Oklahoma [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		2.3				11.2
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.2		1.1		3.3		3.3
Total Revenues		0	[15]			0	[16]
Public Service Co Of Oklahoma [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		2.3	[17]			11.2	[18]
Southwestern Electric Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		535.6
Total Revenues		535.3		517.6		1,411.8		1,343.6
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		9.1				9.1
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		32.8				32.8				30.2
Revenue Textuals [Abstract]
Revenue from Related Parties		8.7		7.7		20.2		20.4
Southwestern Electric Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		20.3				20.3				$ 11
Southwestern Electric Power Co [Member] | 2018 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		9.1				9.1
Southwestern Electric Power Co [Member] | 2019-2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Southwestern Electric Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0				0
Southwestern Electric Power Co [Member] | 2022 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		446.3				1,145.4
Southwestern Electric Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		214				512.3
Southwestern Electric Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		142.6				378.6
Southwestern Electric Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		87.5				248.1
Southwestern Electric Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.2				6.4
Southwestern Electric Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		82.7				246.1
Southwestern Electric Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		53.2	[9]			168.8	[10]
Southwestern Electric Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		29.5	[11]			77.3	[12]
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		6.6	[13]			18	[14]
Southwestern Electric Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers						1,409.5
Southwestern Electric Power Co [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(0.3)				2.3
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.6		0.4		1.2		1.4
Total Revenues		0	[15]			0	[16]
Southwestern Electric Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(0.3)	[17]			2.3	[18]
Consolidation Eliminations [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0		0		0		0
Total Revenues		(247.6)		(226.1)		(674.1)		(727.9)
Revenue Textuals [Abstract]
Revenue from Related Parties		(247.6)		(226.1)		(674.1)		(727.9)
Consolidation Eliminations [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Consolidation Eliminations [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Consolidation Eliminations [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Consolidation Eliminations [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Consolidation Eliminations [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Consolidation Eliminations [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(340.1)				(675.9)
Consolidation Eliminations [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(98.5)	[1]			(155.2)	[2]
Consolidation Eliminations [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(241.6)	[3]			(520.7)	[4]
Consolidation Eliminations [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Consolidation Eliminations [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		49.5	[5]			1.8	[6]
Consolidation Eliminations [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(290.6)				(674.1)
Consolidation Eliminations [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		43				0
Consolidation Eliminations [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		43	[5]			0	[6]
Consolidation Eliminations [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		0	[7]			0	[8]
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]
Total Revenues		2,636.7		2,482.2		7,393.7		6,893.1
Revenue Textuals [Abstract]
Revenue from Related Parties		26.5		28.4		61.3		73.8
Vertically Integrated Utilities [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2,289.4				6,395.1
Vertically Integrated Utilities [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,048.7				2,906.9
Vertically Integrated Utilities [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		618.5				1,693.9
Vertically Integrated Utilities [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		573.2				1,655.2
Vertically Integrated Utilities [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		49				139.1
Vertically Integrated Utilities [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		297				894.9
Vertically Integrated Utilities [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		224.2	[1]			686.5	[2]
Vertically Integrated Utilities [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		72.8	[3]			208.4	[4]
Vertically Integrated Utilities [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		40.3	[5]			121.8	[6]
Vertically Integrated Utilities [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2,626.7				7,411.8
Vertically Integrated Utilities [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		10				(18.1)
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		9.8	[5]			1.1	[6]
Vertically Integrated Utilities [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		0.2	[7]			(19.2)	[8]
Transmission And Distribution Utilities [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		1,211.5		1,173.3		3,510.9		3,313.2
Revenue Textuals [Abstract]
Revenue from Related Parties		30.6		23.6		60.9		70.5
Transmission And Distribution Utilities [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,082.6				3,069.6
Transmission And Distribution Utilities [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		612.2				1,711
Transmission And Distribution Utilities [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		336.7				962.6
Transmission And Distribution Utilities [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		123.9				366.8
Transmission And Distribution Utilities [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		9.8				29.2
Transmission And Distribution Utilities [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		88				272.6
Transmission And Distribution Utilities [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[1]			0	[2]
Transmission And Distribution Utilities [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		88	[3]			272.6	[4]
Transmission And Distribution Utilities [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		69.9	[5]			165.1	[6]
Transmission And Distribution Utilities [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,240.5				3,507.3
Transmission And Distribution Utilities [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(29)				3.6
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		8.9	[5]			51.9	[6]
Transmission And Distribution Utilities [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(37.9)	[7]			(48.3)	[8]
AEP Transmission Holdco [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		187.2				605.2
AEP Transmission Holdco [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
AEP Transmission Holdco [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
AEP Transmission Holdco [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
AEP Transmission Holdco [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
AEP Transmission Holdco [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
AEP Transmission Holdco [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		201.4				633.9
AEP Transmission Holdco [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[1]			0	[2]
AEP Transmission Holdco [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		201.4	[3]			633.9	[4]
Revenue Textuals [Abstract]
Revenue from Related Parties		147				444
AEP Transmission Holdco [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
AEP Transmission Holdco [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.7	[5]			11.1	[6]
AEP Transmission Holdco [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		202.1				645
AEP Transmission Holdco [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(14.9)				(39.8)
AEP Transmission Holdco [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		0	[5]			0	[6]
AEP Transmission Holdco [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(14.9)	[7]			(39.8)	[8]
Generation And Marketing [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		521.6		465.5		1,487.4		1,467.5
Revenue Textuals [Abstract]
Revenue from Related Parties		35.1		24		88.1		80.7
Generation And Marketing [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Generation And Marketing [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Generation And Marketing [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Generation And Marketing [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Generation And Marketing [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Generation And Marketing [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		514.2				1,453.6
Generation And Marketing [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		115.1	[1]			413.4	[2]
Revenue Textuals [Abstract]
Revenue from Related Parties		35				87
Generation And Marketing [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[3]			0	[4]
Generation And Marketing [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		399.1				1,040.2
Generation And Marketing [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		12.7	[5]			15	[6]
Generation And Marketing [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		526.9				1,468.6
Generation And Marketing [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(5.3)				18.8
Generation And Marketing [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		(5.3)	[5]			18.8	[6]
Generation And Marketing [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		0	[7]			0	[8]
Other Segments [Member]
Disaggregation of Revenue [Abstract]
Total Revenues	[21]	23.7		31.3		71.5		86.7
Revenue Textuals [Abstract]
Revenue from Related Parties	[21]	20.1		16.7		55.1		46.8
Other Segments [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[1]			0	[2]
Other Segments [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0	[3]			0	[4]
Other Segments [Member] | Marketing, Competitive Retail and Renewable [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0				0
Other Segments [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		21.5	[5]			64.8	[6]
Other Segments [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		21.5				64.8
Other Segments [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		2.2				6.7
Other Segments [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[21]	3.6		$ 14.6		16.4		$ 39.9
Total Revenues		2.2	[5]			6.7	[6]
Other Segments [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Total Revenues		$ 0	[7]			$ 0	[8]
[1]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $35 million. The remaining affiliated amounts are immaterial.
[2]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $87 million. The remaining affiliated amounts are immaterial.
[3]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $147 million. The remaining affiliated amounts are immaterial.
[4]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $444 million. The remaining affiliated amounts are immaterial.
[5]	Amounts include affiliated and nonaffiliated revenues.
[6]	Amounts include affiliated and nonaffiliated revenues.
[7]	The alternative revenue for Transmission and Distribution Utilities is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
[8]	The alternative revenue for Transmission and Distribution Utilities is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
[9]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.
[10]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.
[11]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $146 million. The remaining affiliated amounts are immaterial.
[12]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $448 million. The remaining affiliated amounts are immaterial.
[13]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial
[14]	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial
[15]	Amounts include affiliated and nonaffiliated revenues.
[16]	Amounts include affiliated and nonaffiliated revenues.
[17]	The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
[18]	The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note
[19]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[20]	The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
[21]	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 and interest expense and other nonallocated costs.