Ohio Power (OHIPN) 8-K26 May 23Other EventsFinancial data

Company Profile

Cover

Cover		12 Months Ended
Cover	May 26, 2023	Dec. 31, 2022
Entity Information [Line Items]
Document Type	8-K
Document Period End Date	May 26, 2023
Entity File Number	1-3525
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	13-4922640
Entity Address, Address Line One	1 Riverside Plaza,
Entity Address, City or Town	Columbus,
Entity Address, State or Province	OH
Entity Address, Postal Zip Code	43215-2373
City Area Code	(614)
Local Phone Number	716-1000
Entity Central Index Key	0000004904
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Auditor Firm ID	238
Auditor Location	Columbus, Ohio
Auditor Name	PricewaterhouseCoopers LLP
AEP Texas Inc. [Member]
Entity Information [Line Items]
Entity File Number	333-221643
Entity Registrant Name	AEP TEXAS INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0007707
Entity Central Index Key	0001721781
Auditor Firm ID		238
Auditor Location		Columbus, Ohio
Auditor Name		PricewaterhouseCoopers LLP
AEP Transmission Co [Member]
Entity Information [Line Items]
Entity File Number	333-217143
Entity Registrant Name	AEP TRANSMISSION COMPANY, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-1125168
Entity Central Index Key	0001702494
Auditor Firm ID	238
Auditor Location	Columbus, Ohio
Auditor Name	PricewaterhouseCoopers LLP
Appalachian Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3457
Entity Registrant Name	APPALACHIAN POWER COMPANY
Entity Incorporation, State or Country Code	VA
Entity Tax Identification Number	54-0124790
Entity Central Index Key	0000006879
Auditor Firm ID		238
Auditor Location		Columbus, Ohio
Auditor Name		PricewaterhouseCoopers LLP
Indiana Michigan Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3570
Entity Registrant Name	INDIANA MICHIGAN POWER COMPANY
Entity Incorporation, State or Country Code	IN
Entity Tax Identification Number	35-0410455
Entity Central Index Key	0000050172
Auditor Firm ID		238
Auditor Location		Columbus, Ohio
Auditor Name		PricewaterhouseCoopers LLP
Ohio Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-6543
Entity Registrant Name	OHIO POWER COMPANY
Entity Incorporation, State or Country Code	OH
Entity Tax Identification Number	31-4271000
Entity Central Index Key	0000073986
Auditor Firm ID		238
Auditor Location		Columbus, Ohio
Auditor Name		PricewaterhouseCoopers LLP
Public Service Co Of Oklahoma [Member]
Entity Information [Line Items]
Entity File Number	0-343
Entity Registrant Name	PUBLIC SERVICE COMPANY OF OKLAHOMA
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-0410895
Entity Central Index Key	0000081027
Auditor Firm ID		238
Auditor Location		Columbus, Ohio
Auditor Name		PricewaterhouseCoopers LLP
Southwestern Electric Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3146
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER COMPANY
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	72-0323455
Entity Central Index Key	0000092487
Auditor Firm ID		238
Auditor Location		Columbus, Ohio
Auditor Name		PricewaterhouseCoopers LLP
The NASDAQ Stock Market \| Common Stock, $6.50 par value [Member]
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $6.50 par value
Trading Symbol	AEP
Security Exchange Name	NASDAQ
The NASDAQ Stock Market \| 6.125% Corporate Units
Entity Information [Line Items]
Title of 12(b) Security	6.125% Corporate Units
Trading Symbol	AEPPZ
Security Exchange Name	NASDAQ

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
Consolidated Statements of Income - USD ($) $ in Millions	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Revenues
Revenue from Contracts with Customers	$ 19,639.5		$ 16,792		$ 14,918.5
Sales to AEP Affiliates	0		0		0
TOTAL REVENUES	19,639.5		16,792		14,918.5
Expenses
Other Operation	2,878.1		2,547.7		2,572.4
Maintenance	1,249.4		1,121.8		1,010.4
Loss on the Expected Sale of the Kentucky Operations	363.3		0		0
Asset Impairments and Other Related Charges	48.8		11.6		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37)		0		0
Gain on Sale of Merchant Generation Assets	(116.3)		0		0
Depreciation and Amortization	3,202.8		2,825.7		2,682.8
Taxes Other Than Income Taxes	1,469.8		1,407.6		1,295.5
TOTAL EXPENSES	16,156.8		13,380.7		11,930.8
OPERATING INCOME (LOSS)	3,482.7		3,411.3		2,987.7
Other Income (Expense):
Other Income	11.6		41.4		57
Allowance for Equity Funds Used During Construction	133.7		139.7		148.1
Non-Service Cost Components of Net Periodic Benefit Cost	188.5		118.6		119
Interest Expense	(1,396.1)		(1,199.1)		(1,165.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	2,420.4		2,511.9		2,146.1
Income Tax Expense/Benefit	5.4		115.5		40.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(109.4)		91.7		91.1
Net Income (Loss)	2,305.6		2,488.1		2,196.7
Net Income Attributable to Noncontrolling Interests	(1.6)		0		(3.4)
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 2,307.2		$ 2,488.1		$ 2,200.1
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	511,841,946		500,522,177		495,718,223
Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders	$ 4.51		$ 4.97		$ 4.44
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	513,484,609		501,784,032		497,226,867
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 4.49		$ 4.96		$ 4.42
Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	$ 11,292.8		$ 9,852.2		$ 8,753.2
Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	5,489.6		4,464.1		4,238.7
Generation and Marketing Revenues [Member]
Revenues
Revenue from Contracts with Customers	2,448.9		2,108.3		1,621
Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	408.2		367.4		305.6
TOTAL REVENUES	360.3	[1],[2]	227.6	[3],[4]	61.5	[5],[6]
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold	7,097.9		5,466.3		4,369.7
AEP Texas Inc. [Member]
Revenues
Revenue from Contracts with Customers	1,848		1,587.7		1,528
Sales to AEP Affiliates	3.5		3.9		90.8
TOTAL REVENUES	1,846.8		1,593.8		1,618.9
Expenses
Other Operation	594.2		489.5		488.9
Maintenance	93.5		86.2		80.5
Depreciation and Amortization	452.4		387		529.8
Taxes Other Than Income Taxes	157.5		155.1		136.4
TOTAL EXPENSES	1,297.6		1,117.8		1,249.3
OPERATING INCOME (LOSS)	549.2		476		369.6
Other Income (Expense):
Interest Income	3.6		0.8		1.4
Allowance for Equity Funds Used During Construction	19.7		21.5		19.4
Non-Service Cost Components of Net Periodic Benefit Cost	16.7		11.1		11.2
Interest Expense	(208.7)		(176.5)		(171.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	380.5		332.9		229.8
Income Tax Expense/Benefit	72.6		43.1		(11.2)
Net Income (Loss)	307.9		289.8		241
AEP Texas Inc. [Member] \| Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	1,839.7		1,586.4		1,524.9
AEP Texas Inc. [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	3.6		3.5		3.2
TOTAL REVENUES	0	[7]	0	[8]	87.5	[9]
AEP Texas Inc. [Member] \| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold	0		0		13.7
AEP Transmission Co [Member]
Revenues
Revenue from Contracts with Customers	1,651.7		1,410.9		1,232.7
Sales to AEP Affiliates	1,354.5		1,171.5		954.6
TOTAL REVENUES	1,624.5		1,469.3		1,145.7
Expenses
Other Operation	136.3		105.5		99.8
Maintenance	17.2		18.4		10.2
Depreciation and Amortization	346.2		297.3		249
Taxes Other Than Income Taxes	271.1		238.8		205.2
TOTAL EXPENSES	770.8		660		564.2
OPERATING INCOME (LOSS)	853.7		809.3		581.5
Other Income (Expense):
Interest Income	1.6		0.5		2.4
Allowance for Equity Funds Used During Construction	70.7		67.2		74
Interest Expense	(162.7)		(141.2)		(127.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	763.3		735.8		530.1
Income Tax Expense/Benefit	169.1		144.1		106.7
Net Income (Loss)	594.2		591.7		423.4
Earnings Per Share
Provision for Refund-Affiliated	(70.7)		(17.6)		(58.3)
Provision for Refund-Nonaffiliated	(14.2)		(2.4)		(16)
AEP Transmission Co [Member] \| Transmission [Member]
Revenues
Revenue from Contracts with Customers	354.9		317.8		265.4
AEP Transmission Co [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	(0.2)		0.3		0.6
TOTAL REVENUES	0	[7]	0	[8]	0	[9]
Appalachian Power Co [Member]
Revenues
Revenue from Contracts with Customers	3,520.7		3,092.9		2,809.2
Sales to AEP Affiliates	256.1		197.9		174.7
TOTAL REVENUES	3,519.9		3,105.2		2,796.2
Expenses
Other Operation	724.1		610		530.5
Maintenance	297.8		265.5		226.8
Asset Impairments and Other Related Charges	24.9		0		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37)		0		0
Re-Establishment of Regulatory Asset - Coal Fired Generation	0		0		(49)
Depreciation and Amortization	575.9		546.2		507.5
Taxes Other Than Income Taxes	158.2		154.2		150.2
TOTAL EXPENSES	2,917.8		2,555.8		2,239.6
OPERATING INCOME (LOSS)	602.1		549.4		556.6
Other Income (Expense):
Interest Income	3.5		1		1.6
Allowance for Equity Funds Used During Construction	11.7		15.6		14.6
Non-Service Cost Components of Net Periodic Benefit Cost	29		19		18.8
Interest Expense	(233.9)		(214)		(217.6)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	412.4		371		374
Income Tax Expense/Benefit	18.2		22.1		4.3
Net Income (Loss)	394.2		348.9		369.7
Appalachian Power Co [Member] \| Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	3,245.5		2,895.5		2,610.9
Appalachian Power Co [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	18.3		11.8		10.6
TOTAL REVENUES	0.5	[7]	0	[8]	0	[9]
Appalachian Power Co [Member] \| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold	1,173.9		979.9		873.6
Indiana Michigan Power Co [Member]
Revenues
Revenue from Contracts with Customers	2,659.7		2,330.7		2,236
Sales to AEP Affiliates	15.3		3.8		10.5
Other Revenues - Affiliated	54.3		54		60.8
TOTAL REVENUES	2,669.6		2,326.7		2,241.8
Expenses
Purchased Electricity from AEP Affiliates	241.8		217.9		172.8
Other Operation	621		645.2		650
Maintenance	227.2		210		193.2
Depreciation and Amortization	527.2		446		411.6
Taxes Other Than Income Taxes	97		110.8		107.1
TOTAL EXPENSES	2,249.7		1,968.8		1,878.9
OPERATING INCOME (LOSS)	419.9		357.9		362.9
Other Income (Expense):
Other Income	9.3		11.7		10
Allowance for Equity Funds Used During Construction	9.8		12.8		11.5
Non-Service Cost Components of Net Periodic Benefit Cost	24.9		16.4		16.7
Interest Expense	(125.2)		(116.8)		(112.3)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	328.9		269.2		277.3
Income Tax Expense/Benefit	4.2		(10.6)		(7.5)
Net Income (Loss)	324.7		279.8		284.8
Indiana Michigan Power Co [Member] \| Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	2,588.3		2,261.2		2,165.3
Indiana Michigan Power Co [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	11.7		7.7		5.2
Sales to AEP Affiliates	62		60		69
TOTAL REVENUES	(0.1)	[7]	0	[8]	0	[9]
Indiana Michigan Power Co [Member] \| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold	535.5		338.9		344.2
Ohio Power Co [Member]
Revenues
Revenue from Contracts with Customers	3,672.1		2,837.5		2,665
Sales to AEP Affiliates	18.8		24.8		41.5
TOTAL REVENUES	3,665.1		2,899.1		2,749.1
Expenses
Purchased Electricity from AEP Affiliates	9.8		51.9		119.7
Other Operation	982		836.8		822.6
Maintenance	185.5		158.2		127.1
Depreciation and Amortization	294.3		303.3		276.6
Taxes Other Than Income Taxes	502.4		485.7		450.2
TOTAL EXPENSES	3,251.4		2,513.9		2,345.4
OPERATING INCOME (LOSS)	413.7		385.2		403.7
Other Income (Expense):
Interest Income	0.9		0.6		1
Other Income	0.4		1.2		1.6
Allowance for Equity Funds Used During Construction	13.9		10.8		12.5
Non-Service Cost Components of Net Periodic Benefit Cost	22.1		14.6		15
Interest Expense	(119.6)		(124.4)		(117.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	331.4		288		316.6
Income Tax Expense/Benefit	44.2		34.4		45.2
Equity Earnings (Loss) of Unconsolidated Subsidiaries	0.6		0		0
Net Income (Loss)	287.8		253.6		271.4
Ohio Power Co [Member] \| Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	3,635.3		2,863.7		2,698.6
Ohio Power Co [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	11		10.6		9
TOTAL REVENUES	18.6	[7]	19	[8]	17.5	[9]
Ohio Power Co [Member] \| Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	1,277.4		678		549.2
Public Service Co Of Oklahoma [Member]
Revenues
Revenue from Contracts with Customers	1,875.7		1,474.3		1,263.9
Sales to AEP Affiliates	2.9		4.2		5.2
TOTAL REVENUES	1,874.7		1,474.4		1,266.1
Expenses
Other Operation	400.4		353.8		327.3
Maintenance	114.4		97.2		98.4
Depreciation and Amortization	230.1		196.6		173.5
Taxes Other Than Income Taxes	57.5		49.6		47.5
TOTAL EXPENSES	1,693.9		1,281.5		1,090.2
OPERATING INCOME (LOSS)	180.8		192.9		175.9
Other Income (Expense):
Interest Income	7.4		4.3		0.1
Allowance for Equity Funds Used During Construction	1.5		2.4		4
Non-Service Cost Components of Net Periodic Benefit Cost	12.5		8.5		8.5
Interest Expense	(83.8)		(62.9)		(60.3)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	118.4		145.2		128.2
Income Tax Expense/Benefit	(49.2)		4.1		5.2
Net Income (Loss)	167.6		141.1		123
Public Service Co Of Oklahoma [Member] \| Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	1,865.6		1,465.3		1,246.1
Public Service Co Of Oklahoma [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	6.2		4.9		14.8
TOTAL REVENUES	0	[7]	0	[8]	0	[9]
Public Service Co Of Oklahoma [Member] \| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold	891.5		584.3		443.5
Southwestern Electric Power Co [Member]
Revenues
Revenue from Contracts with Customers	2,283.2		2,126		1,735.3
Sales to AEP Affiliates	59.5		41.4		41
Provision for Refund	(5.6)		(0.4)		(2)
TOTAL REVENUES	2,284.4		2,131.8		1,738.5
Expenses
Other Operation	424.7		360.3		338.3
Maintenance	148.6		136.7		129.7
Asset Impairments and Other Related Charges	0		11.6		0
Depreciation and Amortization	324.8		295		272.7
Taxes Other Than Income Taxes	126.8		117.7		102.8
TOTAL EXPENSES	1,914.4		1,792.3		1,448
OPERATING INCOME (LOSS)	370		339.5		290.5
Other Income (Expense):
Interest Income	17.7		9.2		2.1
Allowance for Equity Funds Used During Construction	4.9		7		7.7
Non-Service Cost Components of Net Periodic Benefit Cost	12.5		8.3		8.4
Interest Expense	(137.4)		(125.9)		(118.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)	267.7		238.1		190.2
Income Tax Expense/Benefit	(25.2)		(0.6)		9.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries	1.4		3.4		2.9
Net Income (Loss)	294.3		242.1		183.7
Net Income Attributable to Noncontrolling Interests	4.2		3.1		2.9
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	290.1		239		180.8
Southwestern Electric Power Co [Member] \| Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	2,228.6		2,088.9		1,696.6
Southwestern Electric Power Co [Member] \| Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	1.9		1.9		2.9
TOTAL REVENUES	0	[7]	0	[8]	0	[9]
Southwestern Electric Power Co [Member] \| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation [Member]
Expenses
Cost of Goods and Services Sold	$ 889.5		$ 871		$ 604.5

[1]Amounts include affiliated and nonaffiliated revenues.[2]Generation & Marketing includes economic hedge activity.[3]Amounts include affiliated and nonaffiliated revenues.[4]Generation & Marketing includes economic hedge activity.[5]Amounts include affiliated and nonaffiliated revenues.[6]Generation & Marketing includes economic hedge activity.[7]Amounts include affiliated and nonaffiliated revenues.[8]Amounts include affiliated and nonaffiliated revenues.[9]Amounts include affiliated and nonaffiliated revenues.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net Income (Loss)	$ 2,305.6	$ 2,488.1	$ 2,196.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	81.4	250.5	6.9
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(10.4)	(8.1)	(7)
Pension and OPEB Funded Status, Net of Tax	(155.4)	27.5	62.7
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax	(16.7)	0	0
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(101.1)	269.9	62.6
TOTAL COMPREHENSIVE INCOME (LOSS)	2,204.5	2,758	2,259.3
Total Comprehensive Income Attributable to Noncontrolling Interest	(1.6)	0	(3.4)
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	2,206.1	2,758	2,262.7
Cash Flow Hedges, Tax	21.6	66.6	1.8
Amortization of Pension and OPEB Deferred Costs, Tax	(2.8)	(2.2)	(1.9)
Pension and OPEB Funded Status, Tax	(41.3)	7.3	16.7
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Tax	(4.4)	0	0
AEP Texas Inc. [Member]
Net Income (Loss)	307.9	289.8	241
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1	1	1.1
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.1	0.2	0.2
Pension and OPEB Funded Status, Net of Tax	(3.2)	1.2	2.6
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(2.1)	2.4	3.9
TOTAL COMPREHENSIVE INCOME (LOSS)	305.8	292.2	244.9
Cash Flow Hedges, Tax	0.3	0.3	0.3
Amortization of Pension and OPEB Deferred Costs, Tax	0	0	0
Pension and OPEB Funded Status, Tax	(0.9)	0.3	0.7
AEP Transmission Co [Member]
Net Income (Loss)	594.2	591.7	423.4
Appalachian Power Co [Member]
Net Income (Loss)	394.2	348.9	369.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.8)	8.3	(1.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(4.3)	(4.2)	(3.8)
Pension and OPEB Funded Status, Net of Tax	(24.1)	13.1	7.7
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(29.2)	17.2	2.2
TOTAL COMPREHENSIVE INCOME (LOSS)	365	366.1	371.9
Cash Flow Hedges, Tax	(0.2)	2.2	(0.5)
Amortization of Pension and OPEB Deferred Costs, Tax	(1.1)	(1.1)	(1)
Pension and OPEB Funded Status, Tax	(6.4)	3.5	2
Indiana Michigan Power Co [Member]
Net Income (Loss)	324.7	279.8	284.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.6	1.6	1.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.3)	(0.1)	(0.1)
Pension and OPEB Funded Status, Net of Tax	(0.3)	4.2	3.1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	1	5.7	4.6
TOTAL COMPREHENSIVE INCOME (LOSS)	325.7	285.5	289.4
Cash Flow Hedges, Tax	0.4	0.4	0.4
Amortization of Pension and OPEB Deferred Costs, Tax	(0.1)	0	0
Pension and OPEB Funded Status, Tax	(0.1)	1.1	0.8
Ohio Power Co [Member]
Net Income (Loss)	287.8	253.6	271.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0	0	0
TOTAL COMPREHENSIVE INCOME (LOSS)	287.8	253.6	271.4
Cash Flow Hedges, Tax	0	0	0
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	167.6	141.1	123
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.3	(0.1)	(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	1.3	(0.1)	(1)
TOTAL COMPREHENSIVE INCOME (LOSS)	168.9	141	122
Cash Flow Hedges, Tax	0.3	0	(0.3)
Southwestern Electric Power Co [Member]
Net Income (Loss)	294.3	242.1	183.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.1)	1.5	1.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1.6)	(1.6)	(1.5)
Pension and OPEB Funded Status, Net of Tax	(9.2)	4.9	3.2
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(10.9)	4.8	3.2
TOTAL COMPREHENSIVE INCOME (LOSS)	283.4	246.9	186.9
Total Comprehensive Income Attributable to Noncontrolling Interest	4.2	3.1	2.9
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	279.2	243.8	184
Cash Flow Hedges, Tax	0	0.4	0.4
Amortization of Pension and OPEB Deferred Costs, Tax	(0.4)	(0.4)	(0.4)
Pension and OPEB Funded Status, Tax	$ (2.5)	$ 1.3	$ 0.9

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] 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]	Santa Rita East [Member]	Santa Rita East [Member] Noncontrolling Interests [Member]
TOTAL MEMBER'S EQUITY				$ 4,009.5															$ 2,480.6									$ 1,528.9
Common Stock, Dividends, Per Share, Declared		$ 2.84
Beginning Balance at Dec. 31, 2019		$ 19,913.2	$ 2,961.1		$ 4,172.4	$ 2,544.4	$ 2,508.5	$ 1,373.3	$ 2,441.1	$ 3,343.4	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,535.6		$ 1,457.9		$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 9,900.9		$ 1,516		$ 2,078.3	$ 1,518.5	$ 1,348.5	$ 851	$ 1,629.5	$ (147.7)	$ (12.8)	$ 5	$ (11.6)	$ 1.1	$ (1.3)	$ 281	$ 0.6
Beginning Balance, Shares at Dec. 31, 2019		514,373,631								514,400,000
Issuance of Common Stock, Value		$ 155								$ 15.9						139.1
Issuance of Common Stock, Shares		2,434,723								2,400,000
Capital Contributions from Member				335				50											335				50
Capital Distribution of Radial Assets to Member				(50)															(50)
Common Stock Dividends		$ (1,424.9)																							(1,415)	[1]
Common Stock Dividends					(200)	(85)	(87.5)																						(200)	(85)	(87.5)
Stockholders Equity ASU 2016-13 Adoption		1.8				(0.4)	0.3	(0.3)	1.6																1.8					(0.4)	0.3	(0.3)	1.6
Reverse Common Stock Split	[2]								0						(135.6)									135.6
Common Stock Dividends - Nonaffiliated									(1.9)																															(9.9)	(1.9)
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,		(86.2)														(85.8)	[3]																							(0.4)
Acquisition																																										$ (43.7)	$ (43.7)
Net Income (Loss)		2,200.1							180.8																2,200.1								180.8
Net Income (Loss) Attributable to Noncontrolling Interests		(3.4)							2.9																															(3.4)	2.9
Net Income (Loss)		2,196.7	241	423.4	369.7	284.8	271.4	123	183.7																		241	423.4	369.7	284.8	271.4	123
Other Comprehensive Income (Loss)		62.6	3.9		2.2	4.6		(1)	3.2																									62.6	3.9	2.2	4.6	(1)	3.2
Ending Balance at Dec. 31, 2020		$ 20,774.5	3,206		4,344.3	2,749.2	2,692.7	1,545.6	2,627.7	$ 3,359.3	260.4	56.6	321.2	157.2	0.1	6,588.9		1,457.9		1,828.7	980.9	838.8	414	812.2	10,687.8		1,757		2,248	1,718.7	1,532.7	974.3	1,811.9	(85.1)	(8.9)	7.2	(7)	0.1	1.9	223.6	1.6
Ending Balance, Shares at Dec. 31, 2020		516,808,354								516,800,000
Dividends Paid to Member				(5)	(200)	(85)	(87.5)	0	0																			(5)
TOTAL MEMBER'S EQUITY				4,712.9															2,765.6									1,947.3
Common Stock, Dividends, Per Share, Declared		$ 3
Issuance of Common Stock, Value		$ 600.5								$ 49.4						551.1
Issuance of Common Stock, Shares		7,607,821								7,600,000
Capital Contributions from Member			96	184				625	280									96	184				625	280
Common Stock Dividends		$ (1,519.5)																							(1,507.7)	[1]
Common Stock Dividends					(62.5)	(250)	(100)	(20)																					(62.5)	(250)	(100)	(20)
Common Stock Dividends - Nonaffiliated									(4.8)																															(11.8)	(4.8)
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,		47.8														32.6	[4]								(1.1)															16.3
Acquisition																																										$ 18.9	$ 18.9
Net Income (Loss)		2,488.1							239																2,488.1								239
Net Income (Loss) Attributable to Noncontrolling Interests		0							3.1																															0	3.1
Net Income (Loss)		2,488.1	289.8	591.7	348.9	279.8	253.6	141.1	242.1																		289.8	591.7	348.9	279.8	253.6	141.1
Other Comprehensive Income (Loss)		269.9	2.4		17.2	5.7		(0.1)	4.8																									269.9	2.4	17.2	5.7	(0.1)	4.8
Ending Balance at Dec. 31, 2021		$ 22,680.2	3,594.2		4,647.9	2,784.7	2,846.3	$ 2,291.6	3,149.8	$ 3,408.7	260.4	56.6	321.2	157.2	0.1	7,172.6		1,553.9		1,828.7	980.9	838.8	1,039	1,092.2	11,667.1		2,046.8		2,534.4	1,748.5	1,686.3	1,095.4	2,050.9	184.8	(6.5)	24.4	(1.3)	0	6.7	247	(0.1)
Ending Balance, Shares at Dec. 31, 2021		524,416,175						10,482,000		524,400,000
Dividends Paid to Member				(112.5)	(62.5)	(250)	(100)	$ (20)	0																			(112.5)
TOTAL MEMBER'S EQUITY				5,376.1															2,949.6									2,426.5
Common Stock, Dividends, Per Share, Declared		$ 3.17
Issuance of Common Stock, Value		$ 826.5								$ 4.4						822.1
Issuance of Common Stock, Shares		683,146								700,000
Capital Contributions from Member			4.3	72.7		7.9	1	3.6	350									4.3	72.7		7.9	1	3.6	350
Common Stock Dividends		$ (1,645.2)																							(1,628.7)	[1]
Common Stock Dividends					(37.5)	(110)	(45)	(45)	(105)																				(37.5)	(110)	(45)	(45)	(105)
Common Stock Dividends - Nonaffiliated									(3.4)																															(16.5)	(3.4)
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,		56.4														56.3																								0.1
Net Income (Loss)		2,307.2							290.1																2,307.2								290.1
Net Income (Loss) Attributable to Noncontrolling Interests		(1.6)							4.2																															(1.6)	4.2
Net Income (Loss)		2,305.6	307.9	594.2	394.2	324.7	287.8	167.6	294.3																		307.9	594.2	394.2	324.7	287.8	167.6
Other Comprehensive Income (Loss)		(101.1)	(2.1)		(29.2)	1		1.3	(10.9)																									(101.1)	(2.1)	(29.2)	1	1.3	(10.9)
Ending Balance at Dec. 31, 2022		$ 24,122.4	$ 3,904.3		4,975.4	3,008.3	3,088.1	$ 2,419.1	3,674.8	$ 3,413.1	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 0.1	$ 8,051		$ 1,558.2		$ 1,828.7	$ 988.8	837.8	$ 1,042.6	$ 1,442.2	$ 12,345.6		$ 2,354.7		$ 2,891.1	$ 1,963.2	$ 1,929.1	$ 1,218	$ 2,236	$ 83.7	$ (8.6)	$ (4.8)	$ (0.3)	$ 1.3	$ (4.2)	$ 229	$ 0.7
Ending Balance, Shares at Dec. 31, 2022		525,099,321						10,482,000		525,100,000
Dividends Paid to Member				(170)	$ (37.5)	$ (110)	(45)	$ (45)	$ (105)																			(170)
Return of Capital to Parent Equity Statement							$ (2)															$ (2)
TOTAL MEMBER'S EQUITY				$ 5,873															$ 3,022.3									$ 2,850.7

[1](a) Cash dividends declared per AEP common share were $3.17, $3.00 and $2.84 for the years ended December 31, 2022, 2021 and 2020, respectively.[2](a) In August 2020, SWEPCo executed a reverse stock split with each 2,048 shares of common stock issued and outstanding being combined into one share of common stock. The common stock of SWEPCo is wholly-owned by Parent.[3](b) [4]Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Current Assets
Cash and Cash Equivalents		$ 509.4	$ 403.4
Restricted Cash		47.1	48
Other Temporary Investments		187.6	220.4
Accounts Receivable:
Customers		1,145.1	737.4
Accrued Unbilled Revenues		322.9	221
Pledged Accounts Receivable - AEP Credit		1,207.4	1,038
Miscellaneous		49.7	33.9
Allowance for Uncollectible Accounts		(57.1)	(55.4)
Total Accounts Receivable		2,668	1,974.9
Fuel		435.1	318
Materials and Supplies		915.1	701.8
Risk Management Assets		348.8	200.4
Accrued Tax Benefits		99.4	121.5
Regulatory Asset for Under-Recovered Fuel Costs		1,310	656
Margin Deposits		82.9	207.6
Prepayments and Other Current Assets		172.1	132.4
TOTAL CURRENT ASSETS		6,775.5	4,984.4
Property, Plant and Equipment
Generation		25,834.2	24,319.6
Transmission		33,266.9	30,816.3
Distribution		27,138.8	25,457.4
Other Property, Plant and Equipment		5,971.8	5,844.9
Construction Work in Progress		4,809.7	3,786.8
Total Property, Plant and Equipment		97,021.4	90,225
Accumulated Depreciation and Amortization		23,682.3	21,920.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		73,339.1	68,304.1
Other Noncurrent Assets
Regulatory Assets		4,762	4,618.8
Securitized Assets		446	552.8
Spent Nuclear Fuel and Decommissioning Trusts		3,341.2	3,867
Goodwill		52.5	52.5
Derivative Asset, Noncurrent		284.1	267
Operating Lease Assets		645.5	589
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		3,757.4	4,433.1
TOTAL OTHER NONCURRENT ASSETS		13,288.7	14,380.2
TOTAL ASSETS		93,403.3	87,668.7
Current Liabilities
Accounts Payable		2,670.8	2,108
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	750	750
Other Short-term Debt		3,362.2	1,864
Total Short-term Debt		4,112.2	2,614
Long-term Debt Due Within One Year		2,486.4	2,353.8
Risk Management Liabilities		145.2	75.5
Customer Deposits		408.8	354
Accrued Taxes		1,714.6	1,631.3
Accrued Interest		336.5	279.3
Obligations Under Operating Leases		113.6	99.8
Regulatory Liability for Over-Recovered Fuel Costs		1.4	1.5
Other Current Liabilities		1,278.2	1,390.7
TOTAL CURRENT LIABILITIES		13,266.3	10,906.4
Noncurrent Liabilities
Long-term Debt		34,314.6	32,203.8
Deferred Income Tax Liabilities, Net		8,896.9	8,644.1
Long-term Risk Management Liabilities		345.2	230.3
Regulatory Liabilities and Deferred Investment Tax Credits		8,115.6	8,834.4
Asset Retirement Obligations		2,879.3	2,692.6
Employee Benefits and Pension Obligations		257.3	328.4
Obligations Under Operating Leases		552.5	501.4
Deferred Credits and Other Noncurrent Liabilities		607.3	603.8
TOTAL NONCURRENT LIABILITIES		55,968.7	54,038.8
TOTAL LIABILITIES		69,235	64,945.2
Rate Matters
Commitments and Contingencies
Contingently Redeemable Performance Share Awards		45.9	43.3
Total Mezzanine Equity		45.9	43.3
Equity
Common Stock		3,413.1	3,408.7
Paid-in Capital		8,051	7,172.6
Retained Earnings		12,345.6	11,667.1
Accumulated Other Comprehensive Income (Loss)		83.7	184.8
TOTAL COMMON SHAREHOLDERS' EQUITY		23,893.4	22,433.2
Noncontrolling Interests		229	247
TOTAL EQUITY		24,122.4	22,680.2
TOTAL LIABILITIES AND EQUITY		$ 93,403.3	$ 87,668.7
Common Stock, Par Value Per Share		$ 6.50	$ 6.50
Common Stock, Shares, Issued		525,099,321	524,416,175
Common Stock, Shares Authorized		600,000,000	600,000,000
Treasury Stock, Shares		11,233,240	20,204,160
Subsidiaries [Member]
Current Assets
Restricted Cash		$ 47.1	$ 48
Other Temporary Investments		182.9	214.8
Short-term Debt:
Long-term Debt Due Within One Year		218.2	190.5
Noncurrent Liabilities
Long-term Debt		755.3	840.5
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents		0.1	0.1
Restricted Cash		32.7	30.4
Advances to Affiliates		6.9	6.9
Accounts Receivable:
Customers		150.9	123.4
Affiliated Companies		11.9	7.9
Accrued Unbilled Revenues		91.4	77.9
Miscellaneous		0.2	0
Allowance for Uncollectible Accounts		(4.2)	(4)
Total Accounts Receivable		250.2	205.2
Materials and Supplies		138.8	73.9
Accrued Tax Benefits		12.2	24.8
Prepayments and Other Current Assets		6	5.9
TOTAL CURRENT ASSETS		446.9	347.2
Property, Plant and Equipment
Transmission		6,301.5	5,849.9
Distribution		5,312.8	4,917.2
Other Property, Plant and Equipment		1,022.8	961.1
Construction Work in Progress		805.2	551.3
Total Property, Plant and Equipment		13,442.3	12,279.5
Accumulated Depreciation and Amortization		1,760.7	1,644.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		11,681.6	10,635.4
Other Noncurrent Assets
Regulatory Assets		298.3	275.2
Securitized Assets		286.4	367.6
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		179	211.3
TOTAL OTHER NONCURRENT ASSETS		763.7	854.1
TOTAL ASSETS		12,892.2	11,836.7
Current Liabilities
Advances from Affiliates		96.5	26.9
Accounts Payable		331	306.3
Affiliated Companies		34.7	32.5
Short-term Debt:
Long-term Debt Due Within One Year		278.5	716
Accrued Taxes		95.5	93.3
Accrued Interest		48.3	44.7
Obligations Under Operating Leases		28.6	14
Other Current Liabilities		130.7	78
TOTAL CURRENT LIABILITIES		1,043.8	1,311.7
Noncurrent Liabilities
Long-term Debt		5,379.3	4,464.8
Deferred Income Tax Liabilities, Net		1,144.2	1,088.9
Regulatory Liabilities and Deferred Investment Tax Credits		1,259.6	1,242
Obligations Under Operating Leases		67.8	61.3
Deferred Credits and Other Noncurrent Liabilities		93.2	73.8
TOTAL NONCURRENT LIABILITIES		7,944.1	6,930.8
TOTAL LIABILITIES		8,987.9	8,242.5
Rate Matters
Commitments and Contingencies
Equity
Paid-in Capital		1,558.2	1,553.9
Retained Earnings		2,354.7	2,046.8
Accumulated Other Comprehensive Income (Loss)		(8.6)	(6.5)
TOTAL EQUITY		3,904.3	3,594.2
TOTAL LIABILITIES AND EQUITY		12,892.2	11,836.7
AEP Texas Inc. [Member] \| AEP Texas Transition and Restoration Funding [Member]
Current Assets
Restricted Cash		32.7	30.4
Other Noncurrent Assets
Securitized Assets		286.4	367.6
Short-term Debt:
Long-term Debt Due Within One Year		93.5	91
Accrued Interest		2.2	2.3
Noncurrent Liabilities
Long-term Debt		221	313.7
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0	0
Advances to Affiliates		4.4	27.2
Accounts Receivable:
Customers		46.9	22.8
Affiliated Companies		119.5	97.3
Total Accounts Receivable		166.4	120.1
Materials and Supplies		10.7	9.3
Accrued Tax Benefits		4.2	5.6
Prepayments and Other Current Assets		3	2.8
TOTAL CURRENT ASSETS		188.7	165
Property, Plant and Equipment
Transmission		12,335.4	11,031
Other Property, Plant and Equipment		476.8	451.9
Construction Work in Progress		1,554.7	1,402.2
Total Property, Plant and Equipment		14,366.9	12,885.1
Accumulated Depreciation and Amortization		1,027	784.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		13,339.9	12,101
Other Noncurrent Assets
Regulatory Assets		7.2	8.5
Deferred Property Taxes		266.6	245.7
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		11.8	4.2
TOTAL OTHER NONCURRENT ASSETS		285.6	258.4
TOTAL ASSETS		13,814.2	12,524.4
Current Liabilities
Advances from Affiliates		229.3	124.8
Accounts Payable		427.8	460.7
Affiliated Companies		82.7	70.4
Short-term Debt:
Long-term Debt Due Within One Year		60	104
Accrued Taxes		529.8	481
Accrued Interest		28.8	28.8
Obligations Under Operating Leases		1.3	0.9
Other Current Liabilities		8.3	3.3
TOTAL CURRENT LIABILITIES		1,368	1,273.9
Noncurrent Liabilities
Long-term Debt		4,722.8	4,239.9
Deferred Income Tax Liabilities, Net		1,056.5	978.3
Regulatory Liabilities and Deferred Investment Tax Credits		723.3	651.7
Obligations Under Operating Leases		1.5	1.3
Deferred Credits and Other Noncurrent Liabilities		69.1	3.2
TOTAL NONCURRENT LIABILITIES		6,573.2	5,874.4
TOTAL LIABILITIES		7,941.2	7,148.3
Rate Matters
Commitments and Contingencies
Equity
Members' Capital		3,022.3	2,949.6
Retained Earnings		2,850.7	2,426.5
TOTAL MEMBER'S EQUITY		5,873	5,376.1
TOTAL LIABILITIES AND EQUITY		13,814.2	12,524.4
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		7.5	2.5
Restricted Cash		14.4	17.6
Advances to Affiliates		19.8	20.8
Accounts Receivable:
Customers		168.9	158.5
Affiliated Companies		94	129.9
Accrued Unbilled Revenues		91.3	54
Miscellaneous		0.3	0.2
Allowance for Uncollectible Accounts		(1.7)	(1.6)
Total Accounts Receivable		352.8	341
Fuel		158.9	67.1
Materials and Supplies		130.6	109.8
Risk Management Assets		69.1	42
Regulatory Asset for Under-Recovered Fuel Costs		473.1	201.3
Margin Deposits		7.4	71.8
Prepayments and Other Current Assets		26	51.4
TOTAL CURRENT ASSETS		1,259.6	925.3
Property, Plant and Equipment
Generation		6,776.8	6,683.9
Transmission		4,482.8	4,322.4
Distribution		4,933	4,683.3
Other Property, Plant and Equipment		883.3	696.6
Construction Work in Progress		705.3	469.9
Total Property, Plant and Equipment		17,781.2	16,856.1
Accumulated Depreciation and Amortization		5,402	5,051.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		12,379.2	11,804.3
Other Noncurrent Assets
Regulatory Assets		1,058.6	757.6
Securitized Assets		159.6	185.1
Employee Benefits and Pension Assets		152.9	220.5
Operating Lease Assets		73.6	66.9
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		138.7	129.2
TOTAL OTHER NONCURRENT ASSETS		1,583.4	1,359.3
TOTAL ASSETS		15,222.2	14,088.9
Current Liabilities
Advances from Affiliates		182.2	199.3
Accounts Payable		451.2	262.2
Affiliated Companies		142.7	118.6
Short-term Debt:
Long-term Debt Due Within One Year		251.8	480.7
Customer Deposits		75.1	73.9
Accrued Taxes		101	119.7
Obligations Under Operating Leases		15	15.1
Other Current Liabilities		171.2	146.4
TOTAL CURRENT LIABILITIES		1,390.2	1,415.9
Noncurrent Liabilities
Long-term Debt		5,158.7	4,458.2
Deferred Income Tax Liabilities, Net		1,992.2	1,804.7
Regulatory Liabilities and Deferred Investment Tax Credits		1,143.6	1,238.8
Asset Retirement Obligations		419.2	394.9
Employee Benefits and Pension Obligations		34.2	41.5
Obligations Under Operating Leases		59.1	52.4
Deferred Credits and Other Noncurrent Liabilities		49.6	34.6
TOTAL NONCURRENT LIABILITIES		8,856.6	8,025.1
TOTAL LIABILITIES		10,246.8	9,441
Rate Matters
Commitments and Contingencies
Equity
Common Stock		260.4	260.4
Paid-in Capital		1,828.7	1,828.7
Retained Earnings		2,891.1	2,534.4
Accumulated Other Comprehensive Income (Loss)		(4.8)	24.4
TOTAL EQUITY		4,975.4	4,647.9
TOTAL LIABILITIES AND EQUITY		$ 15,222.2	$ 14,088.9
Common Stock, No Par Value		$ 0	$ 0
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		$ 4.2	$ 1.3
Advances to Affiliates		23	21.5
Accounts Receivable:
Customers		96.6	40.6
Affiliated Companies		104	78.2
Accrued Unbilled Revenues		0.6	0
Miscellaneous		4.7	2.5
Allowance for Uncollectible Accounts		(0.1)	(0.1)
Total Accounts Receivable		205.8	121.2
Fuel		46.5	56.8
Materials and Supplies		188.1	175.2
Risk Management Assets		15.2	3.3
Regulatory Asset for Under-Recovered Fuel Costs		47.1	6.4
Prepayments and Other Current Assets		41.9	53.7
TOTAL CURRENT ASSETS		571.8	439.4
Property, Plant and Equipment
Generation		5,585.1	5,531.8
Transmission		1,842.2	1,783.1
Distribution		3,024.7	2,800.1
Other Property, Plant and Equipment		839.3	792.9
Construction Work in Progress		253	302.8
Total Property, Plant and Equipment		11,544.3	11,210.7
Accumulated Depreciation and Amortization		4,132.8	3,899.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,411.5	7,310.9
Other Noncurrent Assets
Regulatory Assets		459.6	410.9
Spent Nuclear Fuel and Decommissioning Trusts		3,341.2	3,867
Operating Lease Assets		64.3	63.5
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		270.5	316.5
TOTAL OTHER NONCURRENT ASSETS		4,135.6	4,657.9
TOTAL ASSETS		12,118.9	12,408.2
Current Liabilities
Advances from Affiliates		249.9	93.3
Accounts Payable		173.4	174.4
Affiliated Companies		121.5	94.9
Short-term Debt:
Long-term Debt Due Within One Year		341.8	67
Risk Management Liabilities		0	5
Customer Deposits		48.6	45.2
Accrued Taxes		103.2	106.5
Accrued Interest		36.9	37
Obligations Under Finance Leases		6.9	130.5
Obligations Under Operating Leases		16	15.5
Regulatory Liability for Over-Recovered Fuel Costs		0	1.5
Other Current Liabilities		98.9	123.2
TOTAL CURRENT LIABILITIES		1,197.1	894
Noncurrent Liabilities
Long-term Debt		2,919	3,128
Deferred Income Tax Liabilities, Net		1,157	1,100.2
Regulatory Liabilities and Deferred Investment Tax Credits		1,702.2	2,447.9
Asset Retirement Obligations		2,027.6	1,946.2
Obligations Under Operating Leases		48.9	48.9
Deferred Credits and Other Noncurrent Liabilities		58.8	58.3
TOTAL NONCURRENT LIABILITIES		7,913.5	8,729.5
TOTAL LIABILITIES		9,110.6	9,623.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		988.8	980.9
Retained Earnings		1,963.2	1,748.5
Accumulated Other Comprehensive Income (Loss)		(0.3)	(1.3)
TOTAL EQUITY		3,008.3	2,784.7
TOTAL LIABILITIES AND EQUITY		$ 12,118.9	$ 12,408.2
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]
Short-term Debt:
Long-term Debt Due Within One Year		$ 89.6	$ 65
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		9.6	3
Advances to Affiliates		0	42
Accounts Receivable:
Customers		119.9	71.6
Affiliated Companies		100.9	71.8
Accrued Unbilled Revenues		17.8	1.3
Miscellaneous		0.1	5.9
Allowance for Uncollectible Accounts		(0.1)	(0.6)
Total Accounts Receivable		238.6	150
Materials and Supplies		109.5	74.1
Renewable Energy Credits		35	30.5
Regulatory Asset for Under-Recovered Fuel Costs		3.8	0
Prepayments and Other Current Assets		21.7	27.9
TOTAL CURRENT ASSETS		414.4	327.5
Property, Plant and Equipment
Transmission		3,198.6	2,992.8
Distribution		6,450.3	6,070.6
Other Property, Plant and Equipment		1,051.4	992.9
Construction Work in Progress		474.3	365
Total Property, Plant and Equipment		11,174.6	10,421.3
Accumulated Depreciation and Amortization		2,565.3	2,458.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,609.3	7,963
Other Noncurrent Assets
Regulatory Assets		327.3	293
Operating Lease Assets		73.8	81.2
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		578.3	601.1
TOTAL OTHER NONCURRENT ASSETS		979.4	975.3
TOTAL ASSETS		10,003.1	9,265.8
Current Liabilities
Advances from Affiliates		172.9	0
Accounts Payable		337.3	213.5
Affiliated Companies		126.1	125.4
Short-term Debt:
Long-term Debt Due Within One Year		0.1	0.1
Risk Management Liabilities		1.8	6.7
Customer Deposits		96.5	66.4
Accrued Taxes		733.1	702.4
Obligations Under Operating Leases		13.5	13.1
Other Current Liabilities		154.2	118.1
TOTAL CURRENT LIABILITIES		1,635.5	1,245.7
Noncurrent Liabilities
Long-term Debt		2,970.2	2,968.4
Deferred Income Tax Liabilities, Net		1,101.1	1,000.9
Long-term Risk Management Liabilities		37.9	85.8
Regulatory Liabilities and Deferred Investment Tax Credits		1,044	1,020.9
Obligations Under Operating Leases		60.3	68.6
Deferred Credits and Other Noncurrent Liabilities		66	29.2
TOTAL NONCURRENT LIABILITIES		5,279.5	5,173.8
TOTAL LIABILITIES		6,915	6,419.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		837.8	838.8
Retained Earnings		1,929.1	1,686.3
TOTAL EQUITY		3,088.1	2,846.3
TOTAL LIABILITIES AND EQUITY		$ 10,003.1	$ 9,265.8
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
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		$ 4	$ 1.3
Accounts Receivable:
Customers		70.1	41.5
Affiliated Companies		52.2	35
Miscellaneous		0.8	0.6
Total Accounts Receivable		123.1	77.1
Fuel		11.6	14.5
Materials and Supplies		111.1	56.2
Risk Management Assets		25.3	12.1
Accrued Tax Benefits		16.1	17.6
Regulatory Asset for Under-Recovered Fuel Costs		178.7	194.6
Prepayments and Other Current Assets		21.6	13.4
TOTAL CURRENT ASSETS		491.5	386.8
Property, Plant and Equipment
Generation		2,394.8	1,802.4
Transmission		1,164.4	1,107.7
Distribution		3,216.4	3,004.9
Other Property, Plant and Equipment		469.3	437
Construction Work in Progress		219.3	156
Total Property, Plant and Equipment		7,464.2	6,508
Accumulated Depreciation and Amortization		1,837.7	1,705.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,626.5	4,802.8
Other Noncurrent Assets
Regulatory Assets		653.7	1,037.4
Employee Benefits and Pension Assets		67.3	95.2
Operating Lease Assets		106.1	68.9
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		20.8	7.9
TOTAL OTHER NONCURRENT ASSETS		847.9	1,209.4
TOTAL ASSETS		6,965.9	6,399
Current Liabilities
Advances from Affiliates		364.2	72.3
Accounts Payable		202.9	157.4
Affiliated Companies		76.7	51
Short-term Debt:
Long-term Debt Due Within One Year		0.5	125.5
Customer Deposits		59	56.2
Accrued Taxes		28.7	27
Obligations Under Operating Leases		8.9	6.9
Other Current Liabilities		101.8	66.4
TOTAL CURRENT LIABILITIES		842.7	562.7
Noncurrent Liabilities
Long-term Debt		1,912.3	1,788
Deferred Income Tax Liabilities, Net		788.6	782.3
Regulatory Liabilities and Deferred Investment Tax Credits		809.1	835.3
Asset Retirement Obligations		73.5	57.5
Obligations Under Operating Leases		99.3	62.2
Deferred Credits and Other Noncurrent Liabilities		21.3	19.4
TOTAL NONCURRENT LIABILITIES		3,704.1	3,544.7
TOTAL LIABILITIES		4,546.8	4,107.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		1,042.6	1,039
Retained Earnings		1,218	1,095.4
Accumulated Other Comprehensive Income (Loss)		1.3	0
TOTAL EQUITY		2,419.1	2,291.6
TOTAL LIABILITIES AND EQUITY		$ 6,965.9	$ 6,399
Common Stock, Par Value Per Share		$ 15	$ 15
Common Stock, Shares, Issued		10,482,000	10,482,000
Common Stock, Shares Authorized		11,000,000	11,000,000
Common Stock, Shares Outstanding		9,013,000	9,013,000
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		$ 88.4	$ 51.2
Advances to Affiliates		2.1	155.9
Accounts Receivable:
Customers		38.8	35.8
Affiliated Companies		65.4	38.3
Miscellaneous		10.4	12.3
Total Accounts Receivable		114.6	86.4
Fuel		81.3	82.2
Materials and Supplies		92.1	81.9
Risk Management Assets		16.4	9.8
Accrued Tax Benefits		16.5	17.8
Regulatory Asset for Under-Recovered Fuel Costs		353	143.9
Prepayments and Other Current Assets		47.8	39.4
TOTAL CURRENT ASSETS		812.2	668.5
Property, Plant and Equipment
Generation		5,476.2	4,734.5
Transmission		2,479.8	2,316.9
Distribution		2,659.6	2,514.3
Other Property, Plant and Equipment		804.4	764
Construction Work in Progress		369.5	240.7
Total Property, Plant and Equipment		11,789.5	10,570.4
Accumulated Depreciation and Amortization		3,527.3	3,170.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,262.2	7,400.1
Other Noncurrent Assets
Regulatory Assets		1,042.4	1,005.3
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		262	251.8
TOTAL OTHER NONCURRENT ASSETS		1,304.4	1,257.1
TOTAL ASSETS		10,378.8	9,325.7
Current Liabilities
Advances from Affiliates		310.7	0
Accounts Payable		213.1	163.6
Affiliated Companies		81.7	61.4
Short-term Debt:
Long-term Debt Due Within One Year		6.2	6.2
Risk Management Liabilities		1.4	2.1
Customer Deposits		65.4	62.4
Accrued Taxes		52.8	44.3
Accrued Interest		36	36
Obligations Under Operating Leases		8.4	8.1
Regulatory Liability for Over-Recovered Fuel Costs		1.4	0
Other Current Liabilities		172	154.6
TOTAL CURRENT LIABILITIES		947.7	538.7
Noncurrent Liabilities
Long-term Debt		3,385.4	3,389
Deferred Income Tax Liabilities, Net		1,089.7	1,087.6
Regulatory Liabilities and Deferred Investment Tax Credits		825.7	806.9
Asset Retirement Obligations		237.2	192.7
Employee Benefits and Pension Obligations		29.7	20.3
Obligations Under Operating Leases		120.2	77.7
Deferred Credits and Other Noncurrent Liabilities		68.4	63
TOTAL NONCURRENT LIABILITIES		5,756.3	5,637.2
TOTAL LIABILITIES		6,704	6,175.9
Rate Matters
Commitments and Contingencies
Equity
Common Stock		0.1	0.1
Paid-in Capital		1,442.2	1,092.2
Retained Earnings		2,236	2,050.9
Accumulated Other Comprehensive Income (Loss)		(4.2)	6.7
TOTAL COMMON SHAREHOLDERS' EQUITY		3,674.1	3,149.9
Noncontrolling Interests		0.7	(0.1)
TOTAL EQUITY		3,674.8	3,149.8
TOTAL LIABILITIES AND EQUITY		$ 10,378.8	$ 9,325.7
Common Stock, Par Value Per Share		$ 18	$ 18
Common Stock, Shares Authorized		3,680	3,680
Common Stock, Shares Outstanding		3,680	3,680
Southwestern Electric Power Co [Member] \| Sabine Mining Co [Member]
Current Assets
Cash and Cash Equivalents		$ 84.2	$ 49.9
Accounts Receivable:
Fuel		14.2	13.1
Materials and Supplies		4.2	12
Property, Plant and Equipment
Other Property, Plant and Equipment		219.8	219.9
Accumulated Depreciation and Amortization		$ 212.5	$ 168.1

[1]Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Activites
Net Income (Loss)	$ 2,305.6	$ 2,488.1	$ 2,196.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	3,202.8	2,825.7	2,682.8
Rockport Plant, Unit 2 Lease Amortization	0	135.4	136.5
Deferred Income Taxes	(137.2)	107.6	196.1
Asset Impairments and Other Related Charges	48.8	11.6	0
Allowance for Equity Funds Used During Construction	(133.7)	(139.7)	(148.1)
Mark-to-Market of Risk Management Contracts	15.5	112.3	66.5
Amortization of Nuclear Fuel	82.9	85.3	87.5
Pension Contributions to Qualified Plan Trust	0	0	(110.3)
Property Taxes	(41.2)	(68)	(43.3)
Deferred Fuel Over/Under-Recovery, Net	(319.2)	(1,647.9)	(31.8)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37)	0	0
Gain (Loss) on Disposition of Assets	(116.3)
Change in Regulatory Assets	(46.7)	(238.9)	(337.9)
Change in Other Noncurrent Assets	(187.7)	(126.6)	(151)
Change in Other Noncurrent Liabilities	337.8	206.4	(54.5)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(681.7)	(119.7)	(129.3)
Fuel, Materials and Supplies	(313.9)	300.2	(142.9)
Accounts Payable	489.2	200.6	(35.3)
Accrued Taxes, Net	105.4	218.7	20.1
Rockport Plant, Unit 2 Operating Lease Payments	0	(147.7)	(147.7)
Other Current Assets	109	(151.3)	34.3
Other Current Liabilities	54.3	(212.2)	(255.5)
Net Cash Flows from Operating Activities	5,288	3,839.9	3,832.9
Investing Activities
Construction Expenditures	(6,671.7)	(5,659.6)	(6,246.3)
Purchases of Investment Securities	(2,784.2)	(1,955.1)	(1,678.8)
Sales of Investment Securities	2,743.8	1,901.4	1,644.3
Acquisitions of Nuclear Fuel	(100.7)	(104.5)	(69.7)
Proceeds from Sale of Property, Plant, and Equipment	218	118.9	(71.1)
Other Investing Activities	50.3	32.2	45.5
Net Cash Flows Used for Investing Activities	(7,751.8)	(6,433.9)	(6,233.9)
Financing Activities
Issuance of Common Stock, Net	826.5	600.5	155
Issuance of Long-term Debt	4,649.7	6,486.3	5,626.1
Issuance of Short-term Debt with Original Maturities Greater Than 90 Days	833.9	1,393.3	1,396.5
Change in Short-term Debt with Original Maturities Less Than 90 Days, Net	1,650.4	(487.3)	(448.4)
Retirement of Long-term Debt	(2,345.4)	(2,989.3)	(1,339.8)
Redemption of Short-term Debt with Original Maturities Greater Than 90 Days	(986.1)	(771.3)	(1,307.1)
Principal Payments for Finance Lease Obligations	(309.5)	(64)	(61.7)
Dividends Paid on Common Stock - Nonaffiliated	1,645.2	1,519.5	1,424.9
Redemption of Noncontrolling Interest	0	0	(100.2)
Other Financing Activities	(105.4)	(41.6)	(88.8)
Net Cash Flows from Financing Activities	2,568.9	2,607.1	2,406.7
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	105.1	13.1	5.7
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	451.4	438.3	432.6
Cash and Cash Equivalents at Beginning of Period	403.4
Cash, Cash Equivalents and Restricted Cash at End of Period	556.5	451.4	438.3
Cash and Cash Equivalents at End of Period	509.4	403.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	1,286.3	1,137.2	1,029.1
Net Cash Paid (Received) for Income Taxes	116.8	13.2	(49.1)
Construction Expenditures Included in Current Liabilities as of December 31,	1,258.9	1,180.4	975.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	0	0	33.4
North Central Wind Energy Facilities
Investing Activities
Acquisition of Assets	(1,207.3)	(652.8)	0
Dry Lake Solar Project [Member]
Investing Activities
Acquisition of Assets	0	(114.4)	0
Kentucky Power Co [Member]
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Asset Impairments and Other Related Charges	363.3	0	0
Flat Ridge II
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Equity Method Investment, Other than Temporary Impairment	188	0	0
Mineral Rights
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Gain (Loss) on Disposition of Assets	(116.3)	0	0
AEP Texas Inc. [Member]
Operating Activites
Net Income (Loss)	307.9	289.8	241
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	452.4	387	529.8
Deferred Income Taxes	42.2	43	(15.2)
Allowance for Equity Funds Used During Construction	(19.7)	(21.5)	(19.4)
Pension Contributions to Qualified Plan Trust	0	0	(11.3)
Change in Other Noncurrent Assets	(36.2)	(78.2)	(74)
Change in Other Noncurrent Liabilities	57.6	26.4	(24.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(45)	(21.6)	9.8
Fuel, Materials and Supplies	(64.9)	(3.9)	(7.4)
Accounts Payable	25	8.9	30.2
Accrued Taxes, Net	14.8	7	42.7
Other Current Assets	2.2	(0.9)	0.8
Other Current Liabilities	(4.4)	(39.4)	(88.1)
Net Cash Flows from Operating Activities	731.9	596.6	614.2
Investing Activities
Construction Expenditures	(1,305)	(1,033.3)	(1,295)
Change in Advances to Affiliates, Net	0	0.2	200.1
Other Investing Activities	35.1	32.3	29.5
Net Cash Flows Used for Investing Activities	(1,269.9)	(1,000.8)	(1,065.4)
Financing Activities
Capital Contributions from Member	4.3	96	0
Issuance of Long-term Debt	1,188.6	444.2	652.7
Change in Advances from Affiliates, Net	69.6	(40.2)	67.1
Retirement of Long-term Debt	(716)	(88.7)	(392.1)
Principal Payments for Finance Lease Obligations	(6.8)	(6.7)	(6.3)
Other Financing Activities	0.6	1.3	0.8
Net Cash Flows from Financing Activities	540.3	405.9	322.2
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	2.3	1.7	(129)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	30.5	28.8	157.8
Cash and Cash Equivalents at Beginning of Period	0.1
Cash, Cash Equivalents and Restricted Cash at End of Period	32.8	30.5	28.8
Cash and Cash Equivalents at End of Period	0.1	0.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	198.9	168.9	153.2
Net Cash Paid (Received) for Income Taxes	11	5.7	(42.9)
Noncash Acquisitions Under Finance Leases	6.1	4.4	5.6
Construction Expenditures Included in Current Liabilities as of December 31,	235.4	230	177.8
AEP Transmission Co [Member]
Operating Activites
Net Income (Loss)	594.2	591.7	423.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	346.2	297.3	249
Deferred Income Taxes	62.3	68.5	81.6
Allowance for Equity Funds Used During Construction	(70.7)	(67.2)	(74)
Property Taxes	(20.9)	(25.6)	(26.6)
Change in Other Noncurrent Assets	(7.4)	7.5	(8.2)
Change in Other Noncurrent Liabilities	68.7	3.7	8.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(46.3)	(16)	(19)
Fuel, Materials and Supplies	(1.4)	(0.8)	5.3
Accounts Payable	18.5	(2.2)	77.8
Accrued Taxes, Net	50.2	67.2	62.7
Other Current Assets	(1.1)	6	5.4
Other Current Liabilities	3	(4.4)	(14.5)
Net Cash Flows from Operating Activities	995.3	925.7	771.2
Investing Activities
Construction Expenditures	(1,458.5)	(1,424.8)	(1,615.9)
Change in Advances to Affiliates, Net	22.8	81.9	(23.7)
Acquisition of Assets	(9.8)	(17.9)	(6)
Other Investing Activities	6.3	1.8	5.2
Net Cash Flows Used for Investing Activities	(1,439.2)	(1,359)	(1,640.4)
Financing Activities
Capital Contributions from Member	72.7	184	335
Issuance of Long-term Debt	540.8	443.7	519.5
Change in Advances from Affiliates, Net	104.4	(31.9)	19.7
Retirement of Long-term Debt	(104)	(50)	0
Principal Payments for Finance Lease Obligations	0	0
Dividends Paid on Common Stock	(170)	(112.5)	(5)
Net Cash Flows from Financing Activities	443.9	433.3	869.2
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	0	0	0
Cash and Cash Equivalents at Beginning of Period	0	0	0
Cash and Cash Equivalents at End of Period	0	0	0
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	158.8	132.9	119.7
Net Cash Paid (Received) for Income Taxes	95.5	65.7	22.9
Construction Expenditures Included in Current Liabilities as of December 31,	320.7	358.7	311.9
Noncash Distribution of Radial Assets to Member	0	0	(50)
Appalachian Power Co [Member]
Operating Activites
Net Income (Loss)	394.2	348.9	369.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	575.9	546.2	507.5
Deferred Income Taxes	79.6	15	(26.2)
Asset Impairments and Other Related Charges	24.9	0	0
Allowance for Equity Funds Used During Construction	(11.7)	(15.6)	(14.6)
Mark-to-Market of Risk Management Contracts	(24.4)	(22.3)	18.8
Pension Contributions to Qualified Plan Trust	0	0	(7)
Deferred Fuel Over/Under-Recovery, Net	(501.8)	(196)	37.2
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37)	0	0
Re-Establishment of Regulatory Asset - Coal Fired Generation	0	0	(49)
Change in Other Noncurrent Assets	(75.2)	(68.8)	(40.4)
Change in Other Noncurrent Liabilities	31.4	35.6	11.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(8.5)	(53.3)	(30.2)
Fuel, Materials and Supplies	(113.5)	116.1	(38.2)
Increase (Decrease) in Margin Deposits Outstanding	64.4	(70)	2.8
Accounts Payable	190.1	36.8	(48.1)
Accrued Taxes, Net	6.7	(16.2)	31.3
Other Current Assets	0.2	(2.4)	15.5
Other Current Liabilities	5.9	(42.3)	(28.3)
Net Cash Flows from Operating Activities	601.2	611.7	712
Investing Activities
Construction Expenditures	(1,048.6)	(841.6)	(767.4)
Change in Advances to Affiliates, Net	1	0.6	0.7
Other Investing Activities	42.4	14.5	8.8
Net Cash Flows Used for Investing Activities	(1,005.2)	(826.5)	(757.9)
Financing Activities
Issuance of Long-term Debt	698	494	606.9
Change in Advances from Affiliates, Net	(17.1)	180.7	(218.1)
Retirement of Long-term Debt	(230.4)	(393)	(140.3)
Principal Payments for Finance Lease Obligations	(7.9)	(7.7)	(7.4)
Dividends Paid on Common Stock	(37.5)	(62.5)	(200)
Other Financing Activities	0.7	0.7	0.7
Net Cash Flows from Financing Activities	405.8	212.2	41.8
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1.8	(2.6)	(4.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	20.1	22.7	26.8
Cash and Cash Equivalents at Beginning of Period	2.5
Cash, Cash Equivalents and Restricted Cash at End of Period	21.9	20.1	22.7
Cash and Cash Equivalents at End of Period	7.5	2.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	215.1	207.5	207.1
Net Cash Paid (Received) for Income Taxes	(88.6)	32.8	0
Noncash Acquisitions Under Finance Leases	1.6	1.7	7.2
Construction Expenditures Included in Current Liabilities as of December 31,	164.6	139.1	105.6
Indiana Michigan Power Co [Member]
Operating Activites
Net Income (Loss)	324.7	279.8	284.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	527.2	446	411.6
Rockport Plant, Unit 2 Operating Lease Amortization	0	62.4	69.2
Deferred Income Taxes	(45.1)	(38)	(16.2)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	(49.2)	7.5	24.4
Allowance for Equity Funds Used During Construction	(9.8)	(12.8)	(11.5)
Mark-to-Market of Risk Management Contracts	(16.9)	5.2	5.9
Amortization of Nuclear Fuel	82.9	85.3	87.5
Pension Contributions to Qualified Plan Trust	0	0	(6.4)
Deferred Fuel Over/Under-Recovery, Net	(42.2)	(20.2)	12.4
Change in Other Noncurrent Assets	(47.3)	(54.1)	6.1
Change in Other Noncurrent Liabilities	62.4	7.5	45
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(82.7)	(22.3)	14.5
Fuel, Materials and Supplies	(2.6)	30.1	(34.7)
Accounts Payable	37.3	42.3	(10.8)
Accrued Taxes, Net	9.4	1.6	(20.2)
Rockport Plant, Unit 2 Operating Lease Payments	0	(73.9)	(73.9)
Other Current Assets	19.5	(15.2)	14.3
Other Current Liabilities	(46.9)	2.5	(25.7)
Net Cash Flows from Operating Activities	720.7	733.7	776.3
Investing Activities
Construction Expenditures	(557.8)	(500.9)	(544.7)
Change in Advances to Affiliates, Net	(1.5)	(8.2)	(0.1)
Purchases of Investment Securities	(2,765.4)	(1,928.2)	(1,637.2)
Sales of Investment Securities	2,713.6	1,886.4	1,593.4
Acquisitions of Nuclear Fuel	(100.7)	(104.5)	(69.7)
Other Investing Activities	10.3	22.3	9.4
Net Cash Flows Used for Investing Activities	(701.5)	(633.1)	(648.9)
Financing Activities
Capital Contributions from Member	7.9	0	0
Issuance of Long-term Debt	142.7	546.7	69.5
Change in Advances from Affiliates, Net	156.6	(9.7)	(11.4)
Retirement of Long-term Debt	(83.4)	(383.5)	(93.2)
Principal Payments for Finance Lease Obligations	(130.7)	(6.8)	(6.5)
Dividends Paid on Common Stock	(110)	(250)	(85)
Other Financing Activities	0.6	0.7	0.5
Net Cash Flows from Financing Activities	(16.3)	(102.6)	(126.1)
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	2.9	(2)	1.3
Cash and Cash Equivalents at Beginning of Period	1.3	3.3	2
Cash and Cash Equivalents at End of Period	4.2	1.3	3.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	120.9	110.9	107.6
Net Cash Paid (Received) for Income Taxes	10.1	29.3	42.1
Noncash Acquisitions Under Finance Leases	2.2	132.3	3
Construction Expenditures Included in Current Liabilities as of December 31,	71.9	87.8	62.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	0	0	33.4
Ohio Power Co [Member]
Operating Activites
Net Income (Loss)	287.8	253.6	271.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	294.3	303.3	276.6
Deferred Income Taxes	71.5	30.7	77.2
Allowance for Equity Funds Used During Construction	(13.9)	(10.8)	(12.5)
Mark-to-Market of Risk Management Contracts	(52.8)	(17.8)	6.7
Property Taxes	(20)	(35.3)	(16.6)
Change in Regulatory Assets	30.4	38.3	(69.4)
Change in Other Noncurrent Assets	(87.1)	(40.7)	(49.4)
Change in Other Noncurrent Liabilities	91.1	6.9	(66.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(83.7)	(11.8)	4.2
Fuel, Materials and Supplies	(23.4)	(2.5)	(23.9)
Accounts Payable	112.7	19.1	10.3
Accrued Taxes, Net	27.8	78.2	43.3
Other Current Assets	11.2	(15.7)	1.9
Other Current Liabilities	40.2	(19.9)	(42.5)
Net Cash Flows from Operating Activities	686.1	575.6	410.9
Investing Activities
Construction Expenditures	(872.4)	(732.8)	(813.2)
Change in Advances to Affiliates, Net	42	(42)	0
Other Investing Activities	27.9	21.5	22.2
Net Cash Flows Used for Investing Activities	(802.5)	(753.3)	(791)
Financing Activities
Capital Contributions from Member	1	0	0
Return of Capital to Parent Cash Flows	(2)	0	0
Issuance of Long-term Debt	0	1,037.1	347
Change in Advances from Affiliates, Net	172.9	(259.2)	128.2
Retirement of Long-term Debt	(0.1)	(500.1)	(0.1)
Principal Payments for Finance Lease Obligations	(4.9)	(4.9)	(4.7)
Dividends Paid on Common Stock	(45)	(100)	(87.5)
Other Financing Activities	1.1	0.4	0.9
Net Cash Flows from Financing Activities	123	173.3	383.8
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	6.6	(4.4)	3.7
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	3	7.4	3.7
Cash and Cash Equivalents at Beginning of Period	3
Cash, Cash Equivalents and Restricted Cash at End of Period	9.6	3	7.4
Cash and Cash Equivalents at End of Period	9.6	3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	113.4	119.5	111.2
Net Cash Paid (Received) for Income Taxes	(19.7)	(7.9)	(26.9)
Noncash Acquisitions Under Finance Leases	3	2.5	6.1
Construction Expenditures Included in Current Liabilities as of December 31,	109.7	97.1	76.7
Public Service Co Of Oklahoma [Member]
Operating Activites
Net Income (Loss)	167.6	141.1	123
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	230.1	196.6	173.5
Deferred Income Taxes	(59.4)	113.9	17
Allowance for Equity Funds Used During Construction	(1.5)	(2.4)	(4)
Mark-to-Market of Risk Management Contracts	(13.7)	1.9	5.5
Deferred Fuel Over/Under-Recovery, Net	442.4	(843.8)	(94)
Change in Other Noncurrent Assets	(35.4)	(18.3)	(17.9)
Change in Other Noncurrent Liabilities	29.9	4.4	1.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(46)	(28.7)	1.4
Fuel, Materials and Supplies	(51.1)	1.4	(14.1)
Accounts Payable	57.5	34.2	(29.5)
Accrued Taxes, Net	3.2	(6.5)	3.6
Other Current Assets	(6.3)	(6.3)	4.6
Other Current Liabilities	30.4	(20.8)	(13.7)
Net Cash Flows from Operating Activities	747.7	(433.3)	157
Investing Activities
Construction Expenditures	(447)	(332.1)	(337.9)
Change in Advances to Affiliates, Net	0	0	38.8
Acquisition of Assets	549.3	297	0
Other Investing Activities	4.3	2.4	4
Net Cash Flows Used for Investing Activities	(992)	(626.7)	(295.1)
Financing Activities
Capital Contributions from Member	3.6	625	0
Issuance of Long-term Debt	499.7	1,290	0
Change in Advances from Affiliates, Net	291.9	(83.1)	155.4
Retirement of Long-term Debt	(500.5)	(750.5)	(13.2)
Principal Payments for Finance Lease Obligations	(3.2)	(3.2)	(3.5)
Dividends Paid on Common Stock	(45)	(20)	0
Other Financing Activities	0.5	0.5	0.5
Net Cash Flows from Financing Activities	247	1,058.7	139.2
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	2.7	(1.3)	1.1
Cash and Cash Equivalents at Beginning of Period	1.3	2.6	1.5
Cash and Cash Equivalents at End of Period	4	1.3	2.6
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	79.7	57	59.1
Net Cash Paid (Received) for Income Taxes	(12.5)	(102.9)	(11.8)
Noncash Acquisitions Under Finance Leases	2.8	3.6	3.2
Construction Expenditures Included in Current Liabilities as of December 31,	69.8	56.8	35.5
Noncash Contribution of Radial Assets from Parent	0	0	50
Southwestern Electric Power Co [Member]
Operating Activites
Net Income (Loss)	294.3	242.1	183.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	324.8	295	272.7
Deferred Income Taxes	9.4	16.6	32.4
Asset Impairments and Other Related Charges	0	11.6	0
Allowance for Equity Funds Used During Construction	(4.9)	(7)	(7.7)
Mark-to-Market of Risk Management Contracts	(6.2)	(7.3)	(0.1)
Pension Contributions to Qualified Plan Trust	0	0	(8.9)
Deferred Fuel Over/Under-Recovery, Net	(86.4)	(546.4)	26.3
Change in Regulatory Assets	7.6	(95.6)	(108.4)
Change in Other Noncurrent Assets	42.9	41.9	16.1
Change in Other Noncurrent Liabilities	18.3	(1.1)	25.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(28.2)	(21.5)	7.3
Fuel, Materials and Supplies	(9.3)	126.5	(46.4)
Accounts Payable	34.1	22	11.1
Accrued Taxes, Net	9.8	15.4	(23.1)
Other Current Assets	(9.8)	(3.6)	(2.8)
Other Current Liabilities	(9.8)	8.2	(21.1)
Net Cash Flows from Operating Activities	586.6	96.8	356.3
Investing Activities
Construction Expenditures	(586.4)	(414.6)	(402.7)
Change in Advances to Affiliates, Net	153.8	(153.8)	0
Other Investing Activities	5.5	3.5	10.1
Net Cash Flows Used for Investing Activities	(1,085.1)	(920.7)	(392.6)
Financing Activities
Capital Contributions from Member	350	280	0
Issuance of Long-term Debt	0	1,137.6	0
Change in Short-term Debt with Original Maturities Less Than 90 Days, Net	0	(35)	16.7
Change in Advances from Affiliates, Net	310.7	(124.6)	64.7
Retirement of Long-term Debt	(6.2)	(381.2)	(21.2)
Principal Payments for Finance Lease Obligations	(10.8)	(10.9)	(10.9)
Dividends Paid on Common Stock	(105)	0	0
Dividends Paid on Common Stock - Nonaffiliated	3.4	4.8	1.9
Other Financing Activities	0.4	0.8	0.5
Net Cash Flows from Financing Activities	535.7	861.9	47.9
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	37.2	38	11.6
Cash and Cash Equivalents at Beginning of Period	51.2	13.2	1.6
Cash and Cash Equivalents at End of Period	88.4	51.2	13.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	131.2	116.5	110.7
Net Cash Paid (Received) for Income Taxes	(29.1)	(28.8)	4.3
Noncash Acquisitions Under Finance Leases	3.6	4.8	8.9
Construction Expenditures Included in Current Liabilities as of December 31,	105.6	69	46
Southwestern Electric Power Co [Member] \| North Central Wind Energy Facilities
Investing Activities
Acquisition of Assets	$ (658)	$ (355.8)	$ 0

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
Organization and Summary of Significant Accounting Policies	Dec. 31, 2022
Organization and Summary of Significant Accounting Policies	. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through Sabine, conducts lignite mining operations to fuel the Pirkey Plant. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers continue to pay for certain legacy deferred generation-related costs through PUCO approved riders. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, Operating Agreement, TA and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 16 - Related Party Transactions for additional information. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned subsidiaries and VIEs, of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries, Transition Funding (consolidated VIEs) and Restoration Funding (a consolidated VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. AEP, I&M, PSO and SWEPCo have undivided ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included on the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments and Note 18 - Property, Plant and Equipment for additional information. In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. See “Oklaunion Power Station” section of Note 7 for additional information. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. AEP System Tax Allocation AEP and subsidiaries join in the filing of a consolidated federal income tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group. Restricted Cash (Applies to AEP, AEP Texas and APCo) Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds. Reconciliation of Cash, Cash Equivalents and Restricted Cash The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statement of cash flows: December 31, 2022 AEP AEP Texas APCo (in millions) Cash and Cash Equivalents $ 509.4 $ 0.1 $ 7.5 Restricted Cash 47.1 32.7 14.4 Total Cash, Cash Equivalents and Restricted Cash $ 556.5 $ 32.8 $ 21.9 December 31, 2021 AEP AEP Texas APCo (in millions) Cash and Cash Equivalents $ 403.4 $ 0.1 $ 2.5 Restricted Cash 48.0 30.4 17.6 Total Cash, Cash Equivalents and Restricted Cash $ 451.4 $ 30.5 $ 20.1 Other Temporary Investments (Applies to AEP) Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR, which carries these inventories at the lower of average cost or net realizable value. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the expected sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. For receivables related to KPCo and APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31: Significant Customers of AEP Texas: Reliant Energy, Direct Energy and TXU Energy (a) 2022 2021 2020 Percentage of Total Revenues 45 % 43 % 46 % Percentage of Accounts Receivable – Customers 42 % 41 % 40 % (a) In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica. AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31: Significant Customers of AEPTCo: AEP Subsidiaries 2022 2021 2020 Percentage of Total Revenues 79 % 79 % 78 % Percentage of Total Accounts Receivable 72 % 81 % 78 % The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo) In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost. For AEP’s competitive generation business, management records RECs at the lower of cost or net realizable value. The Registrants follow the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Asset Retirement Obligations (Applies to all Registrants except AEPTCo) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities. I&M records ARO for the decommissioning of the Cook Plant. AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned, inflation, and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo) The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value. Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo) The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen, non-existent or not applicable to merchant operations, changes in fuel costs or sharing of Off-system Sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income. Retail and Wholesale Supply and Delivery of Electricity The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers. Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initia

New Accounting Standards

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2022
New Accounting Pronouncements	2. NEW ACCOUNTING STANDARDS The disclosures in this note apply to all Registrants unless indicated otherwise. During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. There are no new standards expected to have a material impact on the Registrants’ financial statements.

Comprehensive Income

Comprehensive Income	12 Months Ended
Comprehensive Income	Dec. 31, 2022
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except AEPTCo and OPCo. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2022, 2021 and 2020. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information. AEP Cash Flow Hedges Pension and OPEB For the Year Ended December 31, 2022 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2021 $ 163.7 $ (21.3) $ 115.6 $ (73.2) $ 184.8 Change in Fair Value Recognized in AOCI, Net of Tax 477.3 18.4 (a) — (155.4) 340.3 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (b) 0.1 — — — 0.1 Purchased Electricity for Resale (b) (528.6) — — — (528.6) Interest Expense (b) — 4.0 — — 4.0 Amortization of Prior Service Cost (Credit) — — (21.8) — (21.8) Amortization of Actuarial (Gains) Losses — — 8.6 — 8.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit (528.5) 4.0 (13.2) — (537.7) Income Tax (Expense) Benefit (111.0) 0.8 (2.8) — (113.0) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (417.5) 3.2 (10.4) — (424.7) Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI — — — (21.1) (21.1) Income Tax (Expense) Benefit — — — (4.4) (4.4) Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit — — — (16.7) (16.7) Net Current Period Other Comprehensive Income (Loss) 59.8 21.6 (10.4) (172.1) (101.1) Balance in AOCI as of December 31, 2022 $ 223.5 $ 0.3 $ 105.2 $ (245.3) $ 83.7 AEP Cash Flow Hedges Pension and OPEB For the Year Ended December 31, 2021 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 123.7 $ (100.7) $ (85.1) Change in Fair Value Recognized in AOCI, Net of Tax 488.2 21.1 (a) — 27.5 536.8 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (b) 0.7 — — — 0.7 Purchased Electricity for Resale (b) (334.8) — — — (334.8) Interest Expense (b) — 6.5 — — 6.5 Amortization of Prior Service Cost (Credit) — — (19.4) — (19.4) Amortization of Actuarial (Gains) Losses — — 9.1 — 9.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit (334.1) 6.5 (10.3) — (337.9) Income Tax (Expense) Benefit (70.2) 1.4 (2.2) — (71.0) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (263.9) 5.1 (8.1) — (266.9) Net Current Period Other Comprehensive Income (Loss) 224.3 26.2 (8.1) 27.5 269.9 Balance in AOCI as of December 31, 2021 $ 163.7 $ (21.3) $ 115.6 $ (73.2) $ 184.8 Cash Flow Hedges Pension and OPEB For the Year Ended December 31, 2020 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (103.5) $ (11.5) $ 130.7 $ (163.4) $ (147.7) Change in Fair Value Recognized in AOCI, Net of Tax (89.2) (39.9) (a) — 62.7 (66.4) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (b) (0.4) — — — (0.4) Purchased Electricity for Resale (b) 167.6 — — — 167.6 Interest Expense (b) — 4.9 — — 4.9 Amortization of Prior Service Cost (Credit) — — (19.2) — (19.2) Amortization of Actuarial (Gains) Losses — — 10.3 — 10.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 167.2 4.9 (8.9) — 163.2 Income Tax (Expense) Benefit 35.1 1.0 (1.9) — 34.2 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 132.1 3.9 (7.0) — 129.0 Net Current Period Other Comprehensive Income (Loss) 42.9 (36.0) (7.0) 62.7 62.6 Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 123.7 $ (100.7) $ (85.1) AEP Texas Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ (1.3) $ 5.3 $ (10.5) $ (6.5) Change in Fair Value Recognized in AOCI, Net of Tax — — (3.2) (3.2) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.3 — — 1.3 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) Benefit 1.3 0.1 — 1.4 Income Tax (Expense) Benefit 0.3 — — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.0 0.1 — 1.1 Net Current Period Other Comprehensive Income (Loss) 1.0 0.1 (3.2) (2.1) Balance in AOCI as of December 31, 2022 $ (0.3) $ 5.4 $ (13.7) $ (8.6) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (2.3) $ 5.1 $ (11.7) $ (8.9) Change in Fair Value Recognized in AOCI, Net of Tax 0.1 — 1.2 1.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — (0.1) — (0.1) Amortization of Actuarial (Gains) Losses — 0.3 — 0.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.2 0.2 — 1.4 Income Tax (Expense) Benefit 0.3 — — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.9 0.2 — 1.1 Net Current Period Other Comprehensive Income (Loss) 1.0 0.2 1.2 2.4 Balance in AOCI as of December 31, 2021 $ (1.3) $ 5.3 $ (10.5) $ (6.5) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (3.4) $ 4.9 $ (14.3) $ (12.8) Change in Fair Value Recognized in AOCI, Net of Tax 0.1 — 2.6 2.7 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1) — (0.1) Amortization of Actuarial (Gains) Losses — 0.3 — 0.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.3 0.2 — 1.5 Income Tax (Expense) Benefit 0.3 — — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.0 0.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.1 0.2 2.6 3.9 Balance in AOCI as of December 31, 2020 $ (2.3) $ 5.1 $ (11.7) $ (8.9) APCo Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ 7.5 $ 1.2 $ 15.7 $ 24.4 Change in Fair Value Recognized in AOCI, Net of Tax — — (24.1) (24.1) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.0) — — (1.0) Amortization of Prior Service Cost (Credit) — (5.4) — (5.4) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.0) (5.4) — (6.4) Income Tax (Expense) Benefit (0.2) (1.1) — (1.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.8) (4.3) — (5.1) Net Current Period Other Comprehensive Income (Loss) (0.8) (4.3) (24.1) (29.2) Balance in AOCI as of December 31, 2022 $ 6.7 $ (3.1) $ (8.4) $ (4.8) Pension and OPEB Amortization Changes in Cash Flow Hedges - of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 2.6 $ 7.2 Change in Fair Value Recognized in AOCI, Net of Tax 9.2 — 13.1 22.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.1) — — (1.1) Amortization of Prior Service Cost (Credit) — (5.3) — (5.3) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.1) (5.3) — (6.4) Income Tax (Expense) Benefit (0.2) (1.1) — (1.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.9) (4.2) — (5.1) Net Current Period Other Comprehensive Income (Loss) 8.3 (4.2) 13.1 17.2 Balance in AOCI as of December 31, 2021 $ 7.5 $ 1.2 $ 15.7 $ 24.4 Pension and OPEB Amortization Changes in Cash Flow Hedges - of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ 0.9 $ 9.2 $ (5.1) $ 5.0 Change in Fair Value Recognized in AOCI, Net of Tax (0.7) — 7.7 7.0 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.3) — — (1.3) Amortization of Prior Service Cost (Credit) — (5.3) — (5.3) Amortization of Actuarial (Gains) Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3) (4.8) — (6.1) Income Tax (Expense) Benefit (0.3) (1.0) — (1.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0) (3.8) — (4.8) Net Current Period Other Comprehensive Income (Loss) (1.7) (3.8) 7.7 2.2 Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 2.6 $ 7.2 I&M Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ (6.7) $ 4.7 $ 0.7 $ (1.3) Change in Fair Value Recognized in AOCI, Net of Tax — — (0.3) (0.3) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8) — (0.8) Amortization of Actuarial (Gains) Losses — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.0 (0.4) — 1.6 Income Tax (Expense) Benefit 0.4 (0.1) — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 (0.3) — 1.3 Net Current Period Other Comprehensive Income (Loss) 1.6 (0.3) (0.3) 1.0 Balance in AOCI as of December 31, 2022 $ (5.1) $ 4.4 $ 0.4 $ (0.3) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (8.3) $ 4.8 $ (3.5) $ (7.0) Change in Fair Value Recognized in AOCI, Net of Tax — — 4.2 4.2 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8) — (0.8) Amortization of Actuarial (Gains) Losses — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.0 (0.1) — 1.9 Income Tax (Expense) Benefit 0.4 — — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 (0.1) — 1.5 Net Current Period Other Comprehensive Income (Loss) 1.6 (0.1) 4.2 5.7 Balance in AOCI as of December 31, 2021 $ (6.7) $ 4.7 $ 0.7 $ (1.3) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (9.9) $ 4.9 $ (6.6) $ (11.6) Change in Fair Value Recognized in AOCI, Net of Tax — — 3.1 3.1 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8) — (0.8) Amortization of Actuarial (Gains) Losses — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.0 (0.1) — 1.9 Income Tax (Expense) Benefit 0.4 — — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 (0.1) — 1.5 Net Current Period Other Comprehensive Income (Loss) 1.6 (0.1) 3.1 4.6 Balance in AOCI as of December 31, 2020 $ (8.3) $ 4.8 $ (3.5) $ (7.0) PSO Cash Flow Hedge – For the Year Ended December 31, 2022 Interest Rate (in millions) Balance in AOCI as of December 31, 2021 $ — Change in Fair Value Recognized in AOCI, Net of Tax 1.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) — Reclassifications from AOCI, before Income Tax (Expense) Benefit — Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — Net Current Period Other Comprehensive Income (Loss) 1.3 Balance in AOCI as of December 31, 2022 $ 1.3 Cash Flow Hedge – For the Year Ended December 31, 2021 Interest Rate (in millions) Balance in AOCI as of December 31, 2020 $ 0.1 Change in Fair Value Recognized in AOCI, Net of Tax — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (0.1) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1) Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1) Net Current Period Other Comprehensive Income (Loss) (0.1) Balance in AOCI as of December 31, 2021 $ — Cash Flow Hedge – For the Year Ended December 31, 2020 Interest Rate (in millions) Balance in AOCI as of December 31, 2019 $ 1.1 Change in Fair Value Recognized in AOCI, Net of Tax — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.3) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3) Income Tax (Expense) Benefit (0.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0) Net Current Period Other Comprehensive Income (Loss) (1.0) Balance in AOCI as of December 31, 2020 $ 0.1 SWEPCo Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ 1.2 $ (4.4) $ 9.9 $ 6.7 Change in Fair Value Recognized in AOCI, Net of Tax — — (9.2) (9.2) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (0.1) — — (0.1) Amortization of Prior Service Cost (Credit) — (2.0) — (2.0) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1) (2.0) — (2.1) Income Tax (Expense) Benefit — (0.4) — (0.4) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1) (1.6) — (1.7) Net Current Period Other Comprehensive Income (Loss) (0.1) (1.6) (9.2) (10.9) Balance in AOCI as of December 31, 2022 $ 1.1 $ (6.0) $ 0.7 $ (4.2) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (0.3) $ (2.8) $ 5.0 $ 1.9 Change in Fair Value Recognized in AOCI, Net of Tax — — 4.9 4.9 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.9 — — 1.9 Amortization of Prior Service Cost (Credit) — (2.0) — (2.0) Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.9 (2.0) — (0.1) Income Tax (Expense) Benefit 0.4 (0.4) — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.5 (1.6) — (0.1) Net Current Period Other Comprehensive Income (Loss) 1.5 (1.6) 4.9 4.8 Balance in AOCI as of December 31, 2021 $ 1.2 $ (4.4) $ 9.9 $ 6.7 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (1.8) $ (1.3) $ 1.8 $ (1.3) Change in Fair Value Recognized in AOCI, Net of Tax — — 3.2 3.2 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.9 — — 1.9 Amortization of Prior Service Cost (Credit) — (2.0) — (2.0) Amortization of Actuarial (Gains) Losses — 0.1 — 0.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.9 (1.9) — — Income Tax (Expense) Benefit 0.4 (0.4) — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.5 (1.5) — — Net Current Period Other Comprehensive Income (Loss) 1.5 (1.5) 3.2 3.2 Balance in AOCI as of December 31, 2020 $ (0.3) $ (2.8) $ 5.0 $ 1.9 (a) The change in fair value includes $(10) million, $(7) million and $6 million for the years ended December 31, 2022, 2021 and 2020, respectively, related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. (b) Amounts reclassified to the referenced line item on the statements of income.

Rate Matters

Rate Matters	12 Months Ended
Rate Matters	Dec. 31, 2022
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. AEP Texas Rate Matters (Applies to AEP and AEP Texas) AEP Texas Interim Transmission and Distribution Rates Through December 31, 2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $614 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2017-2019 Virginia Triennial Review In November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a statutory 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). APCo appealed this order and a similar order on reconsideration to the Virginia Supreme Court in March 2021, alleging the Virginia SCC erred in finding that costs associated with asset impairments related to APCo early retirement determinations for certain generation facilities should not be attributed to the 2017-2019 test periods under review and deemed fully recovered in the period recorded. In August 2022, the Virginia Supreme Court agreed with this portion of APCo’s appeal and remanded this issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings. In September 2022, as a result of the Virginia Supreme Court ruling, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band. In response to the Virginia Supreme Court’s August 2022 opinion, the Virginia SCC initiated remand proceedings and, in December 2022, issued an order that: (a) approved APCo’s requested $37 million regulatory asset related to previously incurred costs as a result of APCo earning below its 2017-2019 authorized ROE band, (b) authorized a $28 million annual increase in APCo Virginia base rates effective October 2022 and (c) approved a rider to recover approximately $48 million related to this APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s 2022 financial statements reflect the impact of the Virginia SCC’s December 2022 order. 2020-2022 Virginia Triennial Review In March 2023, APCo will submit its required Virginia earnings test calculation to the Virginia SCC for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of December 31, 2022, APCo has deferred approximately $38 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial condition. CCR/ELG Compliance Plan Filings In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from refiling for approval. Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In March 2022, APCo refiled for approval to recover the Virginia jurisdictional share of ELG investments at the Amos and Mountaineer Plants. The Virginia SCC issued a November 2022 order approving this request. 2021 and 2022 ENEC (Expanded Net Energy Cost) Filings In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs. In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review. In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022. In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review. As of December 31, 2022, the Companies’ cumulative ENEC under-recovery was $520 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. June 2022 West Virginia Storm Costs In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of December 31, 2022, the Companies incurred and deferred an estimated $17 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through December 31, 2022, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.5 billion. 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 December 2022, ETT and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement maintains ETT’s previously allowed ROE and capital structure and includes: (a) a $14 million decrease to the current annual revenue requirement effective February 1, 2023, (b) a provision that ETT must make an interim transmission cost of service filing by June 1, 2023, (c) a $2 million line item decrease to the revenue requirement determined in each interim transmission cost of service filing until the filing of the next comprehensive base rate review and (d) no determination of prudence on any transmission investment added since ETT’s last comprehensive base rate review, which would leave the $1.5 billion of cumulative revenues above subject to review in the next comprehensive base rate review. In February 2023, the PUCT approved the stipulation and settlement agreement. As part of the approved agreement, new rates will be implemented in February 2023 and ETT is required to file for a comprehensive base rate review no later than February 1, 2025. I&M Rate Matters (Applies to AEP and I&M) Michigan Power Supply Cost Recovery (PSCR) Reconciliation In April 2022, an ALJ issued a PFD for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In February 2023, the MPSC issued an order resulting in a $1 million disallowance of 2020 OVEC costs. Indiana Earnings Test Filings I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2022, which calculated a credit due to customers of $14 million. In October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in November 2022 through the FAC. As of December 31, 2022, I&M’s financial statements adequately reflect the estimated impact of I&M’s upcoming Indiana earnings test filings. If it is determined that I&M’s over-earnings exceed what has been recorded, it could reduce future net income and cash flows and impact financial condition. 2022 Michigan Integrated Resource Plan (IRP) Filing In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028 and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting MPSC approval of I&M’s Rockport Plant, Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a financial incentive on certain power purchase agreements and load management programs. As of December 31, 2022, I&M’s total net book value for these Rockport Plant, Unit 2 leasehold improvements was approximately $17 million on a Michigan jurisdictional basis. In November 2022, I&M filed a settlement agreement, which included a Rockport Plant, Unit 2 transition plan. Under this plan, I&M Michigan ratepayers will receive a jurisdictional share of post-lease revenues in excess of costs from Rockport Plant, Unit 2’s operations as a merchant facility. In addition, I&M will continue to recover the remaining net book value of Rockport Plant, Unit 2 leasehold improvements through 2028, including a pretax return. In February 2023, the MPSC issued an order approving the settlement agreement without modification. KPCo Rate Matters (Applies to AEP) CCR/ELG Compliance Plan Filings KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of December 31, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028. In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021. In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The WVPSC’s order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs. OPCo Rate Matters (Applies to AEP and OPCo) OVEC Cost Recovery Audits In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact of these disputes; however, if any costs are disallowed or refunds are ordered it could reduce future net income and cash flows and impact financial condition. See "OVEC" section of Note 17 for additional information on AEP and OPCo’s investment in OVEC. June 2022 Storm Costs In June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the transmission and distribution infrastructures. As of December 31, 2022, OPCo had incurred approximately $20 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a motion requesting the PUCO open a formal investigation into the power outages that occurred as a result of the June storms and determine if OPCo was negligent and liable to consumers for damages incurred as a result of the power outages. Separately, in July 2022, the PUCO directed its staff to conduct an after-action review to examine the circumstances of the event and OPCo’s response to determine if OPCo adhered to the laws and rules in the state, followed its PUCO-approved emergency plan and responded appropriately to the event in an effort to mitigate the negative effects. In January 2023, the PUCO Staff issued a report which concluded OPCo was required to proactively shut down parts of its distribution system in order to avoid damages to the system and further outages and that OPCo adhered to its emergency plan. The report also directed OPCo to revise its vegetation programs around high voltage transmission lines and recommended that it make improvements to its emergency communications procedures. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Ohio ESP Filings In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. If OPCo is ultimately not permitted to fully collect its ESP rates it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2022 Oklahoma Base Rate Case In November 2022, PSO filed a request with the OCC for a $173 million annual increase in rates based upon a 10.4% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The requested annual revenue increase includes a $47 million annual depreciation expense increase related to the accelerated depreciation recovery of the Northeastern Plant, Unit 3 through 2026, and a $16 million annual amortization expense increase to recover intangible plant over a 5-year useful life instead of a 10-year useful life. PSO’s request also includes recovery of the 154 MW Rock Falls Wind Facility through base rates to aid PSO’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. PSO expects to close on the acquisition and place the Rock Falls Wind Facility in-service during the first quarter of 2023. OCC approval is not a condition precedent to closing on the acquisition of the Rock Falls Wind Facility. In addition, PSO requested an annual formula based rate tariff, with an initial one-year pilot term. In the event the requested formula based rate tariff is denied, PSO has requested an expanded rider to recover certain distribution investments and related expenses as well as an expanded transmission cost recovery rider. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. February 2021 Severe Winter Weather Impacts in SPP In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity as regulatory assets, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma permitting securitized financing of qualified costs from extreme weather events. This legislation provides certain authority to the OCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by the ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve the securitization of PSO’s extraordinary fuel costs and purchases of electricity. In February 2022, the OCC approved the joint stipulation and settlement agreement which included a determination that all of PSO’s extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will serve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to the ODFA. The securitization charges billed to and collected from customers are not included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. The Texas Supreme Court requested comments on rehearing by March 1, 2023. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings. Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of December 31, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $185 million related to revenues collected from February 2013 through December 2022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis. 2016 Texas Base Rate Case In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition. 2020 Texas Base Rate Case In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base. In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. 2020 Louisiana Base Rate Case In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. SWEPCo’s requested annual increase includes accelerated depreciation related to the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which were or are expected to be retired early. SWEPCo also included recovery of Welsh Plant, Unit 2 over the blended useful life of Welsh Plant, Units 1 and 3. SWEPCo subsequently revised the requested annual increase to $95 million to reflect removing hurricane storm restoration costs from the base case filing, to modify the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information. In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, (c) an $8 million reduction in fuel rates, (d) an adoption of a 3-year formula rate term subject to an earnings band and (e) the recovery of certa

Effects of Regulation

Effects of Regulation	12 Months Ended
Effects of Regulation	Dec. 31, 2022
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Coal-Fired Generation Plants (Applies to AEP, PSO and SWEPCo) Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which has resulted in, and in the future may result in, a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives. Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition. Regulated Generating Units that have been Retired SWEPCo In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. In January 2023, the LPSC approved a settlement agreement which provided recovery of Welsh Plant, Unit 2 as requested. See “2020 Louisiana Base Rate Case” section of Note 4 for additional information. In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections of Note 4 for additional information. Regulated Generating Units to be Retired PSO In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040. SWEPCo In November 2020, management announced plans to retire Pirkey Plant in 2023 and that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of December 31, 2022, of generating facilities planned for early retirement: Plant Net Book Value Accelerated Depreciation Regulatory Asset Cost of Removal Projected Current Authorized Annual (dollars in millions) Northeastern Plant, Unit 3 $ 136.3 $ 145.8 $ 20.2 (b) 2026 (c) $ 14.9 Pirkey Plant 35.1 179.5 39.8 2023 (d) 11.7 Welsh Plant, Units 1 and 3 416.8 85.6 58.3 (e) 2028 (f) 37.9 (a) Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period. (b) Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement. (c) Northeastern Plant, Unit 3 is currently being recovered through 2040. (d) Pirkey Plant is currently being recovered through 2032 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions. (e) Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement. (f) Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions. Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo) In 2020, management of SWEPCo and CLECO determined DHLC would not develop additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station. The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of December 31, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $112 million, including materials and supplies, net of cost of removal collected in rates. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event. In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $32 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $32 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations. In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause. In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021. Intervenor testimony is due in the first quarter of 2023 and a decision from the PUCT is expected in the third quarter of 2023. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Pirkey Power Plant and Related Fuel Operations (Applies to AEP and SWEPCo) In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and rate riders. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of December 31, 2022, SWEPCo’s share of the net investment in the Pirkey Plant is $215 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $43 million as of December 31, 2022. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Regulatory Assets and Liabilities Regulatory assets and liabilities (as adjusted) are comprised of the following items: AEP December 31, Remaining Recovery Period 2022 2021 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 625.7 $ 409.4 1 year Under-recovered Fuel Costs - does not earn a return 588.5 183.9 1 year Unrecovered Winter Storm Fuel Costs - earns a return (a) 95.8 62.7 1 year Total Current Regulatory Assets $ 1,310.0 $ 656.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Pirkey Plant Accelerated Depreciation $ 116.5 $ 87.0 Welsh Plant, Units 1 and 3 Accelerated Depreciation 85.6 45.9 Unrecovered Winter Storm Fuel Costs 84.6 367.5 Dolet Hills Power Station Fuel Costs - Louisiana 32.0 30.9 Dolet Hills Power Station Accelerated Depreciation (b) 9.7 72.3 Kentucky Deferred Purchased Power Expenses — 47.5 Plant Retirement Costs - Unrecovered Plant, Louisiana — 35.2 Other Regulatory Assets Pending Final Regulatory Approval 27.2 9.3 Total Regulatory Assets Currently Earning a Return 355.6 695.6 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 407.1 298.3 2020-2022 Virginia Triennial Under-Earnings 37.9 15.1 Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9 Other Regulatory Assets Pending Final Regulatory Approval 55.6 56.0 Total Regulatory Assets Currently Not Earning a Return 526.5 395.3 Total Regulatory Assets Pending Final Regulatory Approval 882.1 1,090.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (c) 689.9 715.4 24 years Long-term Under-recovered Fuel Costs - Oklahoma 252.7 — 2 years Long-term Under-recovered Fuel Costs - Virginia 223.3 — 2 years Unrecovered Winter Storm Fuel Costs (d) 148.6 679.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 110.6 110.2 20 years Pirkey Plant Accelerated Depreciation - Louisiana 63.0 — 10 years Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction 56.6 66.6 6 years Kentucky Deferred Purchased Power Expenses 53.0 — 5 years Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station, Louisiana 45.1 — 10 years Meter Replacement Costs 34.2 44.9 5 years Environmental Control Projects 33.9 36.2 18 years Cook Plant Uprate Project 25.3 27.7 11 years Ohio Distribution Decoupling 19.5 41.6 2 years Other Regulatory Assets Approved for Recovery 102.9 119.9 various Total Regulatory Assets Currently Earning a Return 1,858.6 1,841.8 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 975.4 689.3 12 years Plant Retirement Costs - Asset Retirement Obligation Costs 308.5 297.9 20 years Unamortized Loss on Reacquired Debt 104.1 111.6 26 years Cook Plant Nuclear Refueling Outage Levelization 81.2 32.0 3 years Fuel and Purchased Power Adjustment Rider 76.3 40.8 2 years Plant Retirement Costs - Unrecovered Plant, Texas 51.7 51.9 24 years Peak Demand Reduction/Energy Efficiency 41.7 40.8 4 years Unrealized Loss on Forward Commitments 40.1 100.8 10 years Ohio Enhanced Service Reliability Plan 33.3 9.5 2 years Postemployment Benefits 32.1 32.5 3 years 2017-2019 Virginia Triennial Under-Earnings 30.1 — 2 years Vegetation Management 25.8 29.3 3 years Smart Grid Costs 25.4 19.3 2 years PJM/SPP Annual Formula Rate True-up 21.8 18.0 2 years Plant Retirement Costs - Unrecovered Plant, Arkansas 21.1 — 5 years Virginia Transmission Rate Adjustment Clause 18.7 37.2 2 years Storm-Related Costs 11.9 25.4 2 years Texas Transmission Cost Recovery Factor 3.8 30.6 2 years Other Regulatory Assets Approved for Recovery 118.3 119.2 various Total Regulatory Assets Currently Not Earning a Return 2,021.3 1,686.1 Total Regulatory Assets Approved for Recovery 3,879.9 3,527.9 Total Noncurrent Regulatory Assets $ 4,762.0 $ 4,618.8 (a) In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information. (b) 2022 amount includes the FERC jurisdiction. 2021 amounts include Arkansas, Louisiana and FERC jurisdictions. (c) Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information. (d) In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information. AEP December 31, Remaining 2022 2021 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 1.4 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 1.5 Total Current Regulatory Liabilities $ 1.4 $ 1.5 Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 149.7 $ 262.2 Total Regulatory Liabilities Currently Paying a Return 149.7 262.2 Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 4.1 2.3 Total Regulatory Liabilities Currently Not Paying a Return 4.1 2.3 Total Regulatory Liabilities Pending Final Regulatory Determination 153.8 264.5 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 3,392.4 3,229.9 (b) Income Taxes, Net (a) 2,504.5 2,792.0 (c) Rockport Plant, Unit 2 Accelerated Depreciation for Leasehold Improvements 53.8 4.2 6 years Renewable Energy Surcharge - Michigan 23.2 14.9 2 years Other Regulatory Liabilities Approved for Payment 9.5 16.2 various Total Regulatory Liabilities Currently Paying a Return 5,983.4 6,057.2 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 1,318.5 1,939.7 (d) Deferred Investment Tax Credits 237.3 248.5 34 years OVEC Purchased Power 47.1 14.8 2 years Spent Nuclear Fuel 45.8 49.5 (d) Unrealized Gain on Forward Commitments 45.2 40.4 2 years 2017-2019 Virginia Triennial Revenue Provision 39.1 41.6 26 years PJM Costs and Off-system Sales Margin Sharing - Indiana 34.2 — 2 years PJM Transmission Enhancement Refund 34.1 45.5 3 years Over-recovered Fuel Costs - Ohio 32.2 15.2 10 years Transition and Restoration Charges - Texas 29.4 26.3 7 years Peak Demand Reduction/Energy Efficiency 28.6 28.6 2 years Other Regulatory Liabilities Approved for Payment 86.9 62.6 various Total Regulatory Liabilities Currently Not Paying a Return 1,978.4 2,512.7 Total Regulatory Liabilities Approved for Payment 7,961.8 8,569.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,115.6 $ 8,834.4 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $277 million and $468 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. (d) Relieved when plant is decommissioned. AEP Texas December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Texas Mobile Generation Lease Payments $ 17.6 $ — Total Regulatory Assets Currently Earning a Return 17.6 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 26.7 22.4 Vegetation Management Program 5.2 5.2 Texas Retail Electric Provider Bad Debt Expense 4.1 4.1 Other Regulatory Assets Pending Final Regulatory Approval 13.4 9.5 Total Regulatory Assets Currently Not Earning a Return 49.4 41.2 Total Regulatory Assets Pending Final Regulatory Approval 67.0 41.2 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 16.1 22.7 4 years Advanced Metering System — 10.6 Other Regulatory Assets Approved for Recovery 1.4 2.1 various Total Regulatory Assets Currently Earning a Return 17.5 35.4 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 173.2 119.0 12 years Vegetation Management Program 12.1 17.4 3 years Peak Demand Reduction/Energy Efficiency 11.9 14.5 2 years Storm-Related Costs 8.5 12.8 2 years Texas Transmission Cost Recovery Factor 3.8 30.6 2 years Other Regulatory Assets Approved for Recovery 4.3 4.3 various Total Regulatory Assets Currently Not Earning a Return 213.8 198.6 Total Regulatory Assets Approved for Recovery 231.3 234.0 Total Noncurrent Regulatory Assets $ 298.3 $ 275.2 AEP Texas December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 13.0 $ 13.0 Total Regulatory Liabilities Currently Paying a Return 13.0 13.0 Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 1.8 — Total Regulatory Liabilities Currently Not Paying a Return 1.8 — Total Regulatory Liabilities Pending Final Regulatory Determination 14.8 13.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 766.8 744.7 (b) Income Taxes, Net (a) 431.6 445.3 (c) Other Regulatory Liabilities Approved for Payment 4.3 4.8 various Total Regulatory Liabilities Currently Paying a Return 1,202.7 1,194.8 Regulatory Liabilities Currently Not Paying a Return Transition and Restoration Charges 29.4 26.3 7 years Other Regulatory Liabilities Approved for Payment 12.7 7.9 various Total Regulatory Liabilities Currently Not Paying a Return 42.1 34.2 Total Regulatory Liabilities Approved for Payment 1,244.8 1,229.0 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,259.6 $ 1,242.0 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. AEPTCo December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Noncurrent Regulatory Assets Regulatory assets approved for recovery: Regulatory Assets Currently Not Earning a Return PJM/SPP Annual Formula Rate True-up $ 7.2 $ 8.5 2 years Total Regulatory Assets Approved for Recovery 7.2 8.5 Total Noncurrent Regulatory Assets $ 7.2 $ 8.5 AEPTCo December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Noncurrent Regulatory Liabilities Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 8.7 $ 8.7 Total Regulatory Liabilities Pending Final Regulatory Determination 8.7 8.7 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 358.8 271.4 (b) Income Taxes, Net (a) 355.8 371.6 (c) Total Regulatory Liabilities Approved for Payment 714.6 643.0 Total Noncurrent Regulatory Liabilities $ 723.3 $ 651.7 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $16 million and $26 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. APCo December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 180.7 $ 127.2 1 year Under-recovered Fuel Costs - does not earn a return 292.4 74.1 1 year Total Current Regulatory Assets $ 473.1 $ 201.3 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return COVID-19 - Virginia $ 7.0 $ 6.8 Total Regulatory Assets Currently Earning a Return 7.0 6.8 Regulatory Assets Currently Not Earning a Return Storm-Related Costs - West Virginia 72.6 53.7 2020-2022 Virginia Triennial Under-Earnings 37.9 15.1 Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9 Other Regulatory Assets Pending Final Regulatory Approval 1.1 3.6 Total Regulatory Assets Currently Not Earning a Return 137.5 98.3 Total Regulatory Assets Pending Final Regulatory Approval 144.5 105.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Long-term Under-recovered Fuel Costs - Virginia 223.3 — 2 years Plant Retirement Costs - Unrecovered Plant 75.6 110.0 21 years Other Regulatory Assets Approved for Recovery 0.4 0.4 various Total Regulatory Assets Currently Earning a Return 299.3 110.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 303.1 293.1 15 years Pension and OPEB Funded Status 108.3 62.7 12 years Unamortized Loss on Reacquired Debt 74.4 78.2 23 years 2017-2019 Virginia Triennial Under-Earnings 30.1 — 2 years Virginia Transmission Rate Adjustment Clause 18.7 37.2 2 years Virginia Clean Economy Act 16.7 — 2 years Peak Demand Reduction/Energy Efficiency 15.8 17.8 4 years Postemployment Benefits 13.7 13.3 3 years Vegetation Management Program - West Virginia 13.7 11.9 2 years Environmental Compliance Costs 4.3 13.7 2 years Other Regulatory Assets Approved for Recovery 16.0 14.2 various Total Regulatory Assets Currently Not Earning a Return 614.8 542.1 Total Regulatory Assets Approved for Recovery 914.1 652.5 Total Noncurrent Regulatory Assets $ 1,058.6 $ 757.6 APCo December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 30.5 $ 4.5 Total Regulatory Liabilities Pending Final Regulatory Determination 30.5 4.5 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 713.5 703.3 (b) Income Taxes, Net (a) 291.3 432.9 (c) Deferred Investment Tax Credits 0.3 0.3 31 years Total Regulatory Liabilities Currently Paying a Return 1,005.1 1,136.5 Regulatory Liabilities Currently Not Paying a Return 2017-2019 Virginia Triennial Revenue Provision 39.1 41.6 26 years Unrealized Gain on Forward Commitments 34.5 28.2 2 years Over-recovered Deferred Wind Power Costs - Virginia 13.6 8.4 2 years PJM Transmission Enhancement Refund 9.8 13.0 3 years Other Regulatory Liabilities Approved for Payment 11.0 6.6 various Total Regulatory Liabilities Currently Not Paying a Return 108.0 97.8 Total Regulatory Liabilities Approved for Payment 1,113.1 1,234.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,143.6 $ 1,238.8 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $19 million and $84 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. I&M December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Current Regulatory Assets Under-recovered Fuel Costs, Michigan - earns a return $ 9.0 $ 6.4 1 year Under-recovered Fuel Costs, Indiana - does not earn a return 38.1 — 1 year Total Current Regulatory Assets $ 47.1 $ 6.4 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 0.1 Total Regulatory Assets Currently Earning a Return 0.1 0.1 Regulatory Assets Currently Not Earning a Return Storm-Related Costs - Indiana 21.6 — Other Regulatory Assets Pending Final Regulatory Approval 2.0 3.6 Total Regulatory Assets Currently Not Earning a Return 23.6 3.6 Total Regulatory Assets Pending Final Regulatory Approval 23.7 3.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 147.0 170.8 6 years Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction 56.6 66.6 6 years Cook Plant Uprate Project 25.3 27.7 11 years Deferred Cook Plant Life Cycle Management Project Costs - Michigan, FERC 12.1 13.1 12 years Cook Plant Turbine - Indiana 9.0 9.7 16 years Cook Plant Study Costs 8.7 9.4 13 years Other Regulatory Assets Approved for Recovery 11.9 6.0 various Total Regulatory Assets Currently Earning a Return 270.6 303.3 Regulatory Assets Currently Not Earning a Return Cook Plant Nuclear Refueling Outage Levelization 81.2 32.0 3 years Pension and OPEB Funded Status 26.9 — 12 years Unamortized Loss on Reacquired Debt 12.9 14.2 26 years Peak Demand Energy Efficiency 10.3 2.8 2 years Postemployment Benefits 7.7 9.0 3 years Storm-Related Costs - Indiana 3.4 12.6 2 years PJM Costs and Off-system Sales Margin Sharing - Indiana — 15.1 Other Regulatory Assets Approved for Recovery 22.9 18.2 various Total Regulatory Assets Currently Not Earning a Return 165.3 103.9 Total Regulatory Assets Approved for Recovery 435.9 407.2 Total Noncurrent Regulatory Assets $ 459.6 $ 410.9 I&M December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs, Indiana - does not pay a return $ — $ 1.5 Total Current Regulatory Liabilities $ — $ 1.5 Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) (b) $ (87.7) $ — Total Regulatory Liabilities Pending Final Regulatory Determination (87.7) — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 170.7 179.7 (c) Income Taxes, Net (a) 168.6 182.6 (d) Renewable Energy Surcharge - Michigan 23.2 14.9 2 years Other Regulatory Liabilities Approved for Payment 3.0 7.0 various Total Regulatory Liabilities Currently Paying a Return 365.5 384.2 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 1,318.5 1,939.7 (e) Spent Nuclear Fuel 45.8 49.5 (e) PJM Costs and Off-system Sales Margin Sharing - Indiana 34.2 — 2 years Deferred Investment Tax Credits 17.4 22.4 28 years Pension OPEB Funded Status — 27.6 Environmental Cost Rider - Indiana — 10.6 Other Regulatory Liabilities Approved for Payment 8.5 13.9 various Total Regulatory Liabilities Currently Not Paying a Return 1,424.4 2,063.7 Total Regulatory Liabilities Approved for Payment 1,789.9 2,447.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,702.2 $ 2,447.9 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Represents an income tax related regulatory asset, which is presented within net regulatory liabilities on the balance sheet. (c) Relieved as removal costs are incurred. (d) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $42 million and $90 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. (e) Relieved when plant is decommissioned. OPCo December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - does not earn a return $ 3.8 $ — 1 year Total Current Regulatory Assets $ 3.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm-Related Costs $ 33.8 $ 3.8 Total Regulatory Assets Pending Final Regulatory Approval 33.8 3.8 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Ohio Distribution Decoupling 19.5 41.6 2 years Ohio Basic Transmission Cost Rider 14.3 5.2 2 years Ohio Economic Development Rider 1.1 10.1 2 years Total Regulatory Assets Currently Earning a Return 34.9 56.9 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 142.7 83.3 12 years Unrealized Loss on Forward Commitments 40.0 92.1 10 years Ohio Enhanced Service Reliability Plan 33.3 9.5 2 years Smart Grid Costs 25.4 19.3 2 years Postemployment Benefits 6.2 6.2 3 years PJM Load Service Entity Formula Rate True-up — 7.5 Other Regulatory Assets Approved for Recovery 11.0 14.4 various Total Regulatory Assets Currently Not Earning a Return 258.6 232.3 Total Regulatory Assets Approved for Recovery 293.

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
Commitments, Guarantees and Contingencies	Dec. 31, 2022
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS (Applies to all Registrants except AEP Texas and AEPTCo) The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2022: Contractual Commitments - AEP Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 1,499.8 $ 1,711.8 $ 345.4 $ 252.0 $ 3,809.0 Energy and Capacity Purchase Contracts 167.8 377.7 349.1 570.5 1,465.1 Total $ 1,667.6 $ 2,089.5 $ 694.5 $ 822.5 $ 5,274.1 Contractual Commitments - APCo Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 840.9 $ 1,102.9 $ 263.2 $ 9.2 $ 2,216.2 Energy and Capacity Purchase Contracts 40.5 82.7 79.9 127.0 330.1 Total $ 881.4 $ 1,185.6 $ 343.1 $ 136.2 $ 2,546.3 Contractual Commitments - I&M Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 200.9 $ 235.2 $ 53.3 $ 222.4 $ 711.8 Energy and Capacity Purchase Contracts 140.9 290.0 273.8 276.8 981.5 Total $ 341.8 $ 525.2 $ 327.1 $ 499.2 $ 1,693.3 Contractual Commitments - OPCo Less Than 2-3 Years 4-5 Years After Total (in millions) Energy and Capacity Purchase Contracts $ 34.4 $ 66.5 $ 63.7 $ 169.8 $ 334.4 Contractual Commitments - PSO Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 35.8 $ 14.5 $ — $ — $ 50.3 Energy and Capacity Purchase Contracts 47.1 116.3 122.8 91.4 377.6 Total $ 82.9 $ 130.8 $ 122.8 $ 91.4 $ 427.9 Contractual Commitments - SWEPCo Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 133.7 $ 84.7 $ — $ — $ 218.4 Energy and Capacity Purchase Contracts 10.1 31.6 13.2 — 54.9 Total $ 143.8 $ 116.3 $ 13.2 $ — $ 273.3 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below. Letters of Credit (Applies to AEP and AEP Texas) 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 $4 billion and $1 billion revolving credit facilities due in March 2027 and 2024, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2022, no letters of credit were issued under the revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling, as of December 31, 2022, $400 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2022 were as follows: Company Amount Maturity (in millions) AEP $ 287.4 January 2023 to December 2023 AEP Texas 1.8 July 2023 Guarantees of Equity Method Investees (Applies to AEP) In 2019, AEP acquired a 50% ownership interest in five non-consolidated renewable joint ventures and two renewable tax equity partnerships. Parent issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. In September 2022, AEP signed a PSA with a nonaffiliate for AEP’s interest in Flat Ridge 2, one of the five non-consolidated joint ventures. The transaction closed in the fourth quarter of 2022. As of December 31, 2022, the maximum potential amount of future payments associated with the remaining guarantees was $59 million, with the last guarantee expiring in December 2035. The non-contingent liability recorded associated with these guarantees was $5 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. In accordance with the accounting guidance for guarantees, the initial recognition of the non-contingent liabilities increased AEP’s carrying values of the respective equity method investees. Management considered historical losses, economic conditions, and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2022, there were no material liabilities recorded for any indemnifications. AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf. Lease Obligations Certain Registrants lease equipment under master lease agreements. See “Master Lease Agreements” and “AEPRO Boat and Barge Leases” sections of Note 13 for additional information. ENVIRONMENTAL CONTINGENCIES (Applies to All Registrants except AEPTCo) The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2022, AGR, APCo, OPCo and SWEPCo are named as a Potentially Responsible Party (PRP) for one, one, two and one sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are 11 additional sites for which APCo, I&M, KPCo, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law and AEP Texas and SWEPCo share potential liability under state law at another site. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2022, management’s estimates do not anticipate material clean-up costs for identified Superfund sites. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,296 MW Cook Plant under licenses granted by the NRC. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. Management is currently evaluating applying for license extensions for both units. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low-Level Waste Accumulation Disposal The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of Cook Plant. The most recent decommissioning cost study was performed in 2021. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2.2 billion in 2021 non-discounted dollars, with additional ongoing costs of $7 million per year for post decommissioning storage of SNF and an eventual cost of $33 million for the subsequent decommissioning of the SNF storage facility, also in 2021 non-discounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $2 million, $4 million and $4 million for the years ended December 31, 2022, 2021 and 2020, respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2022 and 2021, the total decommissioning trust fund balances were $3 billion and $3.5 billion, respectively. The decrease in the trust fund balance was driven by unfavorable investment performance in 2022. Trust fund earnings increase the fund assets and may decrease the amount remaining to be recovered from customers. Trust fund losses decrease the fund assets and may increase the amount remaining to be recovered from customers. The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) increase or decrease the recorded liability. I&M continues to work with regulators and customers to establish rates designed to collect the estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning increases and cannot be recovered. Spent Nuclear Fuel Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one-mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the DOE through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to $0. As of December 31, 2022 and 2021, fees and related interest of $286 million and $281 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $330 million and $329 million, respectively, to pay the fee, were recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delay in accepting SNF for permanent storage. Under the settlement agreement, I&M received $3 million, $14 million and $24 million in 2022, 2021 and 2020, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2022. The proceeds reduced costs for dry cask storage. As of December 31, 2022 and 2021, I&M deferred $21 million and $3 million, respectively, in Prepayments and Other Current Assets and $3 million and $21 million, respectively, in Deferred Charges and Other Noncurrent Assets on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for additional information. Nuclear Insurance I&M carries nuclear property insurance of $2.7 billion to cover a nuclear incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by a nuclear incident. Insurance coverage for a nonnuclear property incident at Cook Plant is $500 million. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $41 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $13.7 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $450 million of primary coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $275 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $41 million. The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $450 million through commercially available insurance. The next level of liability coverage of up to $13.2 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through a rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section above for additional information. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 2013, the Wilmington Trust Company filed suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit. The transaction closed at the expiration of the Rockport Plant, Unit 2 lease in December 2022 and also resulted in a final settlement of, and release of claims in, the lease litigation. Subsequent to the end of the Rockport Plant, Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Plant, Unit 2 is being billed to I&M under a FERC-approved UPA. I&M’s purchased power from AEGCo and I&M’s 50% ownership share of Rockport Plant, Unit 2 electricity generated represent a merchant resource for I&M until Rockport Plant, Unit 2 is retired in 2028. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. The MPSC issued an order in February 2023 approving the settlement agreement on I&M’s 2022 Integrated Resource Plan (IRP) filing, which included certain cost recovery for the remaining net book value of leasehold improvements made during the term of the Rockport Plant, Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Plant Unit 2, it could reduce future net income and cash flows and impact financial condition. Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs filed a motion for leave to file an amended complaint, which the Court denied on December 1, 2022. The plaintiffs did not file an appeal by the deadline of January 3, 2023. Litigation Related to Ohio House Bill 6 (HB 6) (Applies to AEP and OPCo) In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6. In August 2020, an AEP shareholder filed a putative class action lawsuit in the U.S. District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleged misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint sought monetary damages, among other forms of relief. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling. In January 2021, an AEP shareholder filed a derivative action in the U.S. District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiffs subsequently filed a notice of appeal with the New York appellate court. On January 20, 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York on January 24, 2023. AEP filed a brief in opposition to intervention on February 3, 2023. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the consolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring. In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter is directed to the Board of Directors of AEP and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by directors and officers, and that, following such investigation, AEP commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this investigation will have a material impact on financial condition, results of operations or cash flows. Claims for Indemnification Related to Damages Resulting from the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of Compliance In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several determinations related to the CCR Rule (see “Environmental Issues - Coal Combustion Residual (CCR) Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well as any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Acquisitions, Assets and Liabil

Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments	12 Months Ended
	Dec. 31, 2022
Mergers, Acquisitions and Dispositions Disclosures	ACQUISITIONS, ASSETS AND LIABILITIES HELD FOR SALE, DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to AEP unless indicated otherwise. ACQUISITIONS 2021 Dry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP) In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% ownership interest in the entity that owns the 100 MW Dry Lake Solar Project (collectively referred to as Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to account for the initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information. North Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo) In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities cost approximately $2 billion and consist of Traverse (998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021. In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction for $1.2 billion, the third of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022. In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of the NCWF projects represent asset acquisitions. As of December 31, 2022 and 2021, PSO had approximately $901 million and $316 million and SWEPCo had approximately $1.1 billion and $378 million, respectively, of gross Property, Plant and Equipment on the balance sheets related to the NCWF projects. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of the NCWF projects. The respective Purchase and Sale Agreements (PSAs) include collective interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance, Maverick and Traverse were built upon. The lessee interests in the land contracts were transferred to Sundance, Maverick and Traverse (and subsequently to PSO and SWEPCo) as a part of the closings of the respective PSAs. The current Obligations Under Operating Leases related to the NCWF projects were not material as of December 31, 2022 and 2021 for PSO and SWEPCo. See the table below for the noncurrent Obligations Under Operating Leases for the NCWF projects for PSO and SWEPCo: PSO SWEPCo December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (in millions) Project Sundance $ 12.6 $ 12.6 $ 15.1 $ 15.1 Maverick 18.0 18.0 21.6 21.6 Traverse 39.8 — 47.7 — Total $ 70.4 $ 30.6 $ 84.4 $ 36.7 2020 Desert Sky Wind Farm and Trent Wind Farm (Generation & Marketing Segment) (Applies to AEP) In August 2020, AEP exercised its call right which required the nonaffiliated member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) to sell its noncontrolling interest to AEP. The exercise price for the call right was determined using a discounted cash flow model with agreed input assumptions as well as updates to certain assumptions reasonably expected based on the actual results of the LLCs. As a result, the LLCs are wholly-owned by AEP and management has concluded that the LLCs are no longer VIEs. AEP paid $57 million in cash, derecognized $63 million of Redeemable Noncontrolling Interest within Mezzanine Equity and recorded an increase of $6 million of Paid-In Capital on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information. Santa Rita East (Generation & Marketing Segment) (Applies to AEP) In November 2020, AEP acquired an additional 10% interest in Santa Rita East for approximately $44 million resulting in AEP having a total interest of 85%. The acquisition of the incremental ownership interest was accounted for as an equity transaction in accordance with the accounting guidance for "Consolidation" and reduced Noncontrolling Interests on the balance sheets by approximately $44 million. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information. ASSETS AND LIABILITIES HELD FOR SALE (as adjusted) 2022 Disposition of KPCo and KTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo) In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP had received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR) and the Committee on Foreign Investment in the United States during 2022. Clearance under the HSR expired in January 2023. AEP and Liberty refiled a joint application seeking HSR clearance in February 2023. The sale was also contingent upon FERC approval under Section 203 of the Federal Power Act. The parties to the SPA had certain termination rights if the closing of the sale did not occur by April 26, 2023. Transfer of Ownership FERC Proceedings In December 2021, Liberty, KPCo and KTCo (the applicants) requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application was deficient and that additional information was required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction would not have an adverse effect on rates. In January 2023, AEP, AEPTCo, and Liberty entered into an amendment to the SPA that specified the applicants will submit a new filing for approval under Section 203 of the Federal Power Act. The new filing was submitted to the FERC on February 14, 2023. The applicants requested expedited treatment of the new filing, including an accelerated comment period. In response, the FERC granted a shortened 45 day comment period. The applicants believed the new Section 203 application addressed the concerns raised in the FERC’s December 2022 order. The application contained several additional commitments by Liberty to mitigate potential adverse impacts on FERC jurisdictional rates over the next five years, including: a) maintaining the current return on equity; b) maintaining the current cost cap on equity; c) financing future investments at the current credit rating; and d) capping certain operating and administrative costs. The statute required an order from the FERC within 180 days of the February 14, 2023 filing date in accordance with Section 203 of the Federal Power Act. KPSC Proceedings In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%. Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of December 31, 2022 and 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million and $586 million, respectively. The SPA included a condition precedent to closing requiring the issuance of regulatory orders approving new Mitchell Plant agreements. The KPSC and WVPSC issued orders proposing materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant. Summary As a result of the conditions imposed by the KPSC’s May 2022 order, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with accounting guidance for Fair Value Measurement. In September 2022, AEP, AEPTCo and Liberty entered into an amendment to the SPA which reduced the purchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval of the sale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving new proposed Mitchell Plant agreements. Further, as a result of the reduced purchase price from the September Amendment and the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement. As a result of the December 2022 FERC order and resulting delay in the anticipated timing of the closing of the transaction, AEP recorded an additional $100 million pretax loss ($79 million net of tax) on the expected sale of the Kentucky Operations in December 2022 in accordance with the accounting guidance for Fair Value Measurement. In total, AEP recorded a $363 million pretax loss of ($297 million net of tax) on the expected sale of the Kentucky Operations for the twelve months ended December 31, 2022. Because the depreciation of Kentucky assets continued to be reflected in revenues through customer rates and continued to be reflected in the carryover basis of the rate-regulated assets, AEP and AEPTCo continued to recognize depreciation on those assets. Depreciation expense of $99 million and $4 million associated with KPCo and KTCo was recognized for the year ended December 31, 2022. The Income Before Income Tax Expense (Benefit) of KPCo and KTCo were not material to AEP and AEPTCo on their respective statements of income for the twelve months ended December 31, 2022 and 2021. Termination of Planned Disposition of KPCo and KTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo) In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty’s new Section 203 application seeking approval of the sale. In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023. As a result of the March 2023 filings made by intervenors with the FERC and the Termination Agreement, the assets and liabilities of KPCo and KTCo were reclassified out of Held for Sale on the December 31, 2022 and December 31, 2021 balance sheets of AEP and AEPTCo. Upon reverting to a held and used model, AEP was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value. As a result, AEP’s December 31, 2022 balance sheets reflect a $363 million pretax reduction in the basis of its investment in KPCo’s assets which was recorded in Property, Plant and Equipment. DISPOSITIONS 2022 Disposition of Cardinal Plant (Generation & Marketing Segment) (Applies to AEP) In March 2022, AGR entered into an Asset Purchase agreement with a nonaffiliated electric cooperative to sell Cardinal Plant, Unit 1, a competitive generation asset totaling 595 MWs. The FERC approved the sale in May 2022 and the sale closed in the third quarter of 2022. The proceeds from the sale were not material. Concurrent with the closing of the sale, AGR executed a PPA with the nonaffiliated electric cooperative for rights to Unit 1’s power and capacity through 2028. AGR also retained certain obligations related to environmental remediation. Subsequent to the closing of the sale, AGR continues to recognize Cardinal Plant, Unit 1 on its balance sheet due to continuing involvement through the PPA. As of December 31, 2022, the net book value of Cardinal Plant, Unit 1 was not material. Disposition of Mineral Rights (Generation & Marketing Segment) (Applies to AEP) In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $120 million of proceeds. The sale resulted in a pretax gain of $116 million in the second quarter of 2022. 2021 Disposition of Racine (Generation & Marketing Segment) (Applies to AEP) In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. The sale of Racine closed in the fourth quarter of 2021 resulting in an immaterial gain which is recorded in Other Operation on AEP’s statements of income. 2020 Conesville Plant (Generation & Marketing Segment) (Applies to AEP) In June 2020, AEP and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP paid approximately $98 million over three years, derecognized $106 million in ARO and recorded an immaterial gain on the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million at closing in June 2020 and made additional payments totaling $72 million in quarterly installments from October 2020 to June 2022. Oklaunion Power Station (Transmission and Distribution Segment and Vertically Integrated Utilities Segment) (Applies to AEP, AEP Texas and PSO) In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Oklaunion Power Station site. The sale had an immaterial impact on the financial statements in the fourth quarter of 2020. IMPAIRMENTS 2022 Flat Ridge 2 Wind LLC (Generation & Marketing Segment) (Applies to AEP) In 2019, AEP acquired a 50% ownership interest in five non-consolidated joint ventures, including Flat Ridge 2 Wind LLC (Flat Ridge 2), and two tax equity partnerships. The five non-consolidated joint ventures are jointly owned and operated by BP Wind Energy. Flat Ridge 2 sells electricity to three counterparties through long-term PPAs. Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary. In accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, in the second quarter of 2022 AEP recorded a pretax other than temporary impairment charge of $186 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a non-affiliate. In the third quarter of 2022, AEP recorded an additional $2 million pretax other than temporary impairment charge which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements at closing. 2021 2020 Texas Base Rate Case (Vertically Integrated Utilities Segment) (Applies to AEP and SWEPCo) In January 2022, the PUCT issued a final order which included a return of investment only for the recovery of the Dolet Hills Power Station. As a result of the final order, SWEPCo recorded a disallowance of $12 million associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging denial of a reasonable return or carrying costs on the Dolet Hills Power Station among other items. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. See “2020 Texas Base Rate Case” section of Note 4 for additional information .

Benefit Plans

Benefit Plans	12 Months Ended
Benefit Plans	Dec. 31, 2022
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1. AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans OPEB December 31, Assumption 2022 2021 2022 2021 Discount Rate 5.50 % 2.90 % 5.50 % 2.90 % Interest Crediting Rate 4.25 % 4.00 % NA NA NA Not applicable. Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2022 2021 AEP 5.05 % 5.10 % AEP Texas 5.15 % 5.10 % APCo 4.90 % 4.85 % I&M 5.00 % 5.00 % OPCo 5.35 % 5.30 % PSO 5.15 % 5.10 % SWEPCo 5.00 % 4.95 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2022, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans OPEB Year Ended December 31, Assumption 2022 2021 2020 2022 2021 2020 Discount Rate 2.90 % 2.50 % 3.25 % 2.90 % 2.55 % 3.30 % Interest Crediting Rate 4.00 % 4.00 % 4.00 % NA NA NA Expected Return on Plan Assets 5.25 % 4.75 % 5.75 % 5.50 % 4.75 % 5.50 % NA Not applicable. Pension Plans Year Ended December 31, Assumption – Rate of Compensation Increase (a) 2022 2021 2020 AEP 5.05 % 5.10 % 5.00 % AEP Texas 5.15 % 5.10 % 5.05 % APCo 4.90 % 4.85 % 4.85 % I&M 5.00 % 5.00 % 5.00 % OPCo 5.35 % 5.30 % 5.25 % PSO 5.15 % 5.10 % 5.05 % SWEPCo 5.00 % 4.95 % 4.90 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: December 31, Health Care Trend Rates 2022 2021 Initial 7.50 % 6.25 % Ultimate 4.50 % 4.50 % Year Ultimate Reached 2029 2029 Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2022, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets For the year ended December 31, 2022, the pension plans had an actuarial gain primarily due to an increase in the discount rate and was partially offset by increases in the assumed lump sum conversion rate and cash balance account interest crediting rate. For the year ended December 31, 2022, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and updated per capita cost assumptions. The OPEB plans gains were partially offset by a projected reduction in the Employer Group Waiver Program catastrophic reinsurance offset provided to AEP, resulting from the Inflation Reduction Act as well as an increase in the health care cost trend assumption. For the year ended December 31, 2021, the pension plans had an actuarial gain primarily due to an increase in the discount rate, partially offset by less favorable demographic experience than expected, resulting from the updated census information as of January 1, 2021. For the year ended December 31, 2021, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and an update of the projected reimbursements from the Employer Group Waiver Program under Medicare Part D. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,187.0 $ 5,544.5 $ 1,041.3 $ 1,210.9 Service Cost 123.1 129.2 7.4 9.5 Interest Cost 148.2 137.2 29.2 30.5 Actuarial Gain (983.4) (173.9) (109.8) (120.1) Plan Amendments — — — (5.4) Benefit Payments (402.2) (450.0) (140.1) (126.0) Participant Contributions — — 44.1 41.3 Medicare Subsidy — — 0.5 0.6 Benefit Obligation as of December 31, $ 4,072.7 $ 5,187.0 $ 872.6 $ 1,041.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 5,352.9 $ 5,556.6 $ 2,044.3 $ 1,946.7 Actual Gain (Loss) on Plan Assets (833.7) 239.2 (403.6) 176.5 Company Contributions (a) 7.7 7.1 4.6 5.8 Participant Contributions — — 44.1 41.3 Benefit Payments (402.2) (450.0) (140.1) (126.0) Fair Value of Plan Assets as of December 31, $ 4,124.7 $ 5,352.9 $ 1,549.3 $ 2,044.3 Funded Status as of December 31, $ 52.0 $ 165.9 $ 676.7 $ 1,003.0 (a) No contributions were made to the qualified pension plan for the years ended December 31, 2022 and 2021, respectively. Contributions to the non-qualified pension plans were $8 million and $7 million for the years ended December 31, 2022 and 2021, respectively. Pension Plans OPEB December 31, AEP 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 113.4 $ 244.3 $ 699.5 $ 1,040.8 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3) (7.6) (2.5) (2.7) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (55.1) (70.8) (20.3) (35.1) Funded Status $ 52.0 $ 165.9 $ 676.7 $ 1,003.0 AEP Texas Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 419.8 $ 453.2 $ 80.5 $ 96.3 Service Cost 11.1 11.8 0.5 0.7 Interest Cost 12.1 11.2 2.2 2.4 Actuarial Gain (67.8) (10.9) (7.1) (12.3) Plan Amendments — — — (0.5) Benefit Payments (41.1) (45.5) (10.9) (9.3) Participant Contributions — — 3.4 3.2 Benefit Obligation as of December 31, $ 334.1 $ 419.8 $ 68.6 $ 80.5 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 444.9 $ 474.0 $ 168.8 $ 162.3 Actual Gain (Loss) on Plan Assets (69.2) 16.0 (33.0) 12.5 Company Contributions 0.5 0.4 — 0.1 Participant Contributions — — 3.4 3.2 Benefit Payments (41.1) (45.5) (10.9) (9.3) Fair Value of Plan Assets as of December 31, $ 335.1 $ 444.9 $ 128.3 $ 168.8 Funded Status as of December 31, $ 1.0 $ 25.1 $ 59.7 $ 88.3 Pension Plans OPEB December 31, AEP Texas 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 3.7 $ 28.7 $ 59.7 $ 88.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.4) (0.3) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (2.3) (3.3) — — Funded Status $ 1.0 $ 25.1 $ 59.7 $ 88.3 APCo Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 621.7 $ 670.8 $ 167.3 $ 198.2 Service Cost 11.4 11.9 0.8 1.0 Interest Cost 17.5 16.4 4.7 4.9 Actuarial Gain (123.1) (28.5) (16.2) (21.4) Plan Amendments — — — (0.9) Benefit Payments (41.8) (48.9) (23.0) (21.3) Participant Contributions — — 7.0 6.6 Medicare Subsidy — — 0.1 0.2 Benefit Obligation as of December 31, $ 485.7 $ 621.7 $ 140.7 $ 167.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 683.3 $ 701.3 $ 302.3 $ 293.0 Actual Gain (Loss) on Plan Assets (109.8) 30.9 (59.3) 21.9 Company Contributions — — 1.6 2.1 Participant Contributions — — 7.0 6.6 Benefit Payments (41.8) (48.9) (23.0) (21.3) Fair Value of Plan Assets as of December 31, $ 531.7 $ 683.3 $ 228.6 $ 302.3 Funded Status as of December 31, $ 46.0 $ 61.6 $ 87.9 $ 135.0 Pension Plans OPEB December 31, APCo 2022 2021 2022 2021 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 46.6 $ 62.4 $ 106.3 $ 158.1 Other Current Liabilities – Accrued Short-term Benefit Liability — — (1.6) (1.8) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (0.6) (0.8) (16.8) (21.3) Funded Status $ 46.0 $ 61.6 $ 87.9 $ 135.0 I&M Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 612.1 $ 653.3 $ 118.6 $ 141.4 Service Cost 16.2 17.5 0.9 1.3 Interest Cost 17.0 16.2 3.4 3.5 Actuarial Gain (138.0) (29.5) (8.7) (16.8) Plan Amendments — — — (0.7) Benefit Payments (40.5) (45.4) (18.3) (15.3) Participant Contributions — — 6.0 5.2 Benefit Obligation as of December 31, $ 466.8 $ 612.1 $ 101.9 $ 118.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 681.5 $ 698.1 $ 248.7 $ 238.2 Actual Gain (Loss) on Plan Assets (107.4) 28.8 (45.9) 20.6 Company Contributions 0.1 — — — Participant Contributions — — 6.0 5.2 Benefit Payments (40.5) (45.4) (18.3) (15.3) Fair Value of Plan Assets as of December 31, $ 533.7 $ 681.5 $ 190.5 $ 248.7 Funded Status as of December 31, $ 66.9 $ 69.4 $ 88.6 $ 130.1 Pension Plans OPEB December 31, I&M 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 68.5 $ 71.4 $ 88.6 $ 130.1 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1) (0.1) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.5) (1.9) — — Funded Status $ 66.9 $ 69.4 $ 88.6 $ 130.1 OPCo Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 470.7 $ 510.3 $ 104.9 $ 126.4 Service Cost 11.2 11.4 0.6 0.8 Interest Cost 13.3 12.5 3.0 3.0 Actuarial Gain (97.9) (24.1) (8.9) (15.6) Plan Amendments — — — (0.6) Benefit Payments (33.7) (39.4) (15.5) (13.6) Participant Contributions — — 4.8 4.5 Benefit Obligation as of December 31, $ 363.6 $ 470.7 $ 88.9 $ 104.9 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 524.8 $ 543.1 $ 220.0 $ 213.0 Actual Gain (Loss) on Plan Assets (84.8) 21.1 (43.1) 16.1 Company Contributions 0.1 — — — Participant Contributions — — 4.8 4.5 Benefit Payments (33.7) (39.4) (15.5) (13.6) Fair Value of Plan Assets as of December 31, $ 406.4 $ 524.8 $ 166.2 $ 220.0 Funded Status as of December 31, $ 42.8 $ 54.1 $ 77.3 $ 115.1 Pension Plans OPEB December 31, OPCo 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 43.1 $ 54.8 $ 77.3 $ 115.1 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (0.3) (0.7) — — Funded Status $ 42.8 $ 54.1 $ 77.3 $ 115.1 PSO Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 252.6 $ 279.9 $ 54.4 $ 64.0 Service Cost 7.4 8.0 0.4 0.6 Interest Cost 7.0 6.7 1.5 1.6 Actuarial Gain (52.9) (17.2) (5.2) (6.8) Plan Amendments — — — (0.3) Benefit Payments (21.8) (24.8) (7.9) (7.0) Participant Contributions — — 2.5 2.3 Benefit Obligation as of December 31, $ 192.3 $ 252.6 $ 45.7 $ 54.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 286.2 $ 299.8 $ 114.0 $ 107.8 Actual Gain (Loss) on Plan Assets (46.0) 11.1 (23.2) 10.9 Company Contributions 0.1 0.1 — — Participant Contributions — — 2.5 2.3 Benefit Payments (21.8) (24.8) (7.9) (7.0) Fair Value of Plan Assets as of December 31, $ 218.5 $ 286.2 $ 85.4 $ 114.0 Funded Status as of December 31, $ 26.2 $ 33.6 $ 39.7 $ 59.6 Pension Plans OPEB December 31, PSO 2022 2021 2022 2021 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 27.6 $ 35.5 $ 39.7 $ 59.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1) (0.1) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.3) (1.8) — — Funded Status $ 26.2 $ 33.6 $ 39.7 $ 59.6 SWEPCo Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 317.7 $ 334.5 $ 65.2 $ 77.1 Service Cost 10.6 11.2 0.6 0.8 Interest Cost 9.1 8.5 1.8 1.9 Actuarial Gain (57.9) (3.5) (6.6) (9.2) Plan Amendments — — — (0.4) Benefit Payments (28.8) (33.0) (8.8) (7.6) Participant Contributions — — 2.9 2.6 Benefit Obligation as of December 31, $ 250.7 $ 317.7 $ 55.1 $ 65.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 308.3 $ 326.9 $ 136.6 $ 129.9 Actual Gain (Loss) on Plan Assets (48.3) 14.3 (27.7) 11.7 Company Contributions 0.1 0.1 — — Participant Contributions — — 2.9 2.6 Benefit Payments (28.8) (33.0) (8.8) (7.6) Fair Value of Plan Assets as of December 31, $ 231.3 $ 308.3 $ 103.0 $ 136.6 Funded (Underfunded) Status as of December 31, $ (19.4) $ (9.4) $ 47.9 $ 71.4 Pension Plans OPEB December 31, SWEPCo 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 47.9 $ 71.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1) (0.1) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.3) (9.3) — — Funded (Underfunded) Status $ (19.4) $ (9.4) $ 47.9 $ 71.4 Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI and the items attributable to the change in these components: AEP Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 935.6 $ 894.7 $ 300.0 $ (103.6) Prior Service Cost (Credit) 0.2 0.2 (90.5) (161.9) Recorded as Regulatory Assets $ 841.8 $ 878.0 $ 126.0 $ (195.1) Deferred Income Taxes 19.9 3.6 17.5 (14.7) Net of Tax AOCI 74.1 13.3 66.0 (55.7) AEP Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 103.9 $ (183.4) $ 403.6 $ (205.5) Amortization of Actuarial Loss (63.0) (101.5) — — Prior Service Credit — — — (5.5) Amortization of Prior Service Credit — — 71.4 70.9 Change for the Year Ended December 31, $ 40.9 $ (284.9) $ 475.0 $ (140.1) AEP Texas Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 161.9 $ 144.7 $ 29.7 $ (5.2) Prior Service Credit — — (7.6) (13.7) Recorded as Regulatory Assets $ 151.2 $ 136.7 $ 22.0 $ (17.7) Deferred Income Taxes 2.4 1.8 0.1 (0.2) Net of Tax AOCI 8.3 6.2 — (1.0) AEP Texas Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 22.4 $ (7.5) $ 34.9 $ (17.5) Amortization of Actuarial Loss (5.2) (8.3) — — Prior Service Credit — — — (0.4) Amortization of Prior Service Credit — — 6.1 6.0 Change for the Year Ended December 31, $ 17.2 $ (15.8) $ 41.0 $ (11.9) APCo Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 95.6 $ 83.9 $ 40.5 $ (18.9) Prior Service Credit — — (13.4) (23.8) Recorded as Regulatory Assets $ 93.6 $ 82.5 $ 14.7 $ (19.8) Deferred Income Taxes 0.4 0.3 2.5 (4.9) Net of Tax AOCI 1.6 1.1 9.9 (18.0) APCo Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 19.1 $ (30.4) $ 59.4 $ (30.0) Amortization of Actuarial Loss (7.4) (12.0) — — Prior Service Credit — — — (0.9) Amortization of Prior Service Credit — — 10.4 10.3 Change for the Year Ended December 31, $ 11.7 $ (42.4) $ 69.8 $ (20.6) I&M Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ (6.9) $ (1.6) $ 40.2 $ (10.7) Prior Service Credit — — (12.4) (22.1) Recorded as Regulatory Assets/Liabilities (a) $ 4.8 $ 3.1 $ 22.1 $ (30.7) Deferred Income Taxes (2.4) (1.0) 1.2 (0.4) Net of Tax AOCI (9.3) (3.7) 4.5 (1.7) (a) Recorded as a Regulatory Asset as of December 31, 2022 and recorded as a Regulatory Liability as of December 31, 2021. I&M Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.8 $ (29.4) $ 50.9 $ (26.3) Amortization of Actuarial Loss (7.1) (11.7) — — Prior Service Credit — — — (0.7) Amortization of Prior Service Credit — — 9.7 9.6 Change for the Year Ended December 31, $ (5.3) $ (41.1) $ 60.6 $ (17.4) OPCo Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 124.3 $ 118.1 $ 27.6 $ (18.5) Prior Service Credit — — (9.2) (16.3) Recorded as Regulatory Assets $ 124.3 $ 118.1 $ 18.4 $ (34.8) OPCo Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.7 $ (22.8) $ 46.1 $ (22.1) Amortization of Actuarial Loss (5.5) (9.1) — — Prior Service Credit — — — (0.6) Amortization of Prior Service Credit — — 7.1 7.2 Change for the Year Ended December 31, $ 6.2 $ (31.9) $ 53.2 $ (15.5) PSO Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 38.8 $ 35.0 $ 22.0 $ (2.1) Prior Service Credit — — (5.6) (10.0) Recorded as Regulatory Assets $ 38.8 $ 35.0 $ 16.4 $ (12.1) PSO Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.7 $ (16.0) $ 24.1 $ (12.6) Amortization of Actuarial Loss (2.9) (4.9) — — Prior Service Credit — — — (0.3) Amortization of Prior Service Credit — — 4.4 4.4 Change for the Year Ended December 31, $ 3.8 $ (20.9) $ 28.5 $ (8.5) SWEPCo Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 77.6 $ 76.4 $ 25.0 $ (3.5) Prior Service Credit — — (7.0) (12.3) Recorded as Regulatory Assets $ 77.6 $ 76.4 $ 11.2 $ (8.9) Deferred Income Taxes — — 1.5 (1.4) Net of Tax AOCI — — 5.3 (5.5) SWEPCo Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 5.0 $ (4.3) $ 28.5 $ (15.0) Amortization of Actuarial Loss (3.8) (6.2) — — Prior Service Credit — — — (0.4) Amortization of Prior Service Credit — — 5.3 5.3 Change for the Year Ended December 31, $ 1.2 $ (10.5) $ 33.8 $ (10.1) Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. Pension and OPEB Assets The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan OPEB December 31, Company 2022 2021 2022 2021 AEP Texas 8.1 % 8.3 % 8.3 % 8.3 % APCo 12.9 % 12.8 % 14.8 % 14.8 % I&M 12.9 % 12.7 % 12.3 % 12.2 % OPCo 9.9 % 9.8 % 10.7 % 10.8 % PSO 5.3 % 5.3 % 5.5 % 5.6 % SWEPCo 5.6 % 5.8 % 6.6 % 6.7 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2022: Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities (a): Domestic $ 347.6 $ — $ — $ — $ 347.6 8.4 % International 398.4 — — — 398.4 9.7 % Common Collective Trusts (b) — — — 379.9 379.9 9.2 % Subtotal – Equities 746.0 — — 379.9 1,125.9 27.3 % Fixed Income (a): United States Government and Agency Securities (0.6) 1,071.4 — — 1,070.8 26.0 % Corporate Debt — 891.7 — — 891.7 21.6 % Foreign Debt — 140.2 — — 140.2 3.4 % State and Local Government — 37.0 — — 37.0 0.9 % Other – Asset Backed — 0.8 — — 0.8 — % Subtotal – Fixed Income (0.6) 2,141.1 — — 2,140.5 51.9 % Infrastructure (b) — — — 109.2 109.2 2.6 % Real Estate (b) — — — 276.9 276.9 6.7 % Alternative Investments (b) — — — 319.7 319.7 7.8 % Cash and Cash Equivalents (b) — 64.9 — 58.3 123.2 3.0 % Other – Pending Transactions and Accrued Income (c) — — — 29.3 29.3 0.7 % Total $ 745.4 $ 2,206.0 $ — $ 1,173.3 $ 4,124.7 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (c) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2022: Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 414.1 $ — $ — $ — $ 414.1 26.7 % International 265.0 — — — 265.0 17.1 % Common Collective Trusts (a) — — — 169.1 169.1 10.9 % Subtotal – Equities 679.1 — — 169.1 848.2 54.7 % Fixed Income: Common Collective Trust – Debt (a) — — — 120.3 120.3 7.8 % United States Government and Agency Securities 0.1 155.8 — — 155.9 10.1 % Corporate Debt — 141.5 — — 141.5 9.1 % Foreign Debt — 21.0 — — 21.0 1.4 % State and Local Government 62.9 7.8 — — 70.7 4.6 % Subtotal – Fixed Income 63.0 326.1 — 120.3 509.4 33.0 % Trust Owned Life Insurance: International Equities — 46.7 — — 46.7 3.0 % United States Bonds — 110.3 — — 110.3 7.1 % Subtotal – Trust Owned Life Insurance — 157.0 — — 157.0 10.1 % Cash and Cash Equivalents (a) 23.2 — — 6.7 29.9 1.9 % Other – Pending Transactions and Accrued Income (b) — — — 4.8 4.8 0.3 % Total $ 765.3 $ 483.1 $ — $ 300.9 $ 1,549.3 100.0 % (a) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2021: Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities (a): Domestic $ 388.9 $ — $ — $ — $ 388.9 7.2 % International 465.7 — — — 465.7 8.7 % Common Collective Trusts (b) — — — 463.9 463.9 8.7 % Subtotal – Equities 854.6 — — 463.9 1,318.5 24.6 % Fixed Income (a): United States Government and Agency Securities 0.1 1,557.6 — — 1,557.7 29.1 % Corporate Debt — 1,295.9 — — 1,295.9 24.2 % Foreign Debt — 259.4 — — 259.4 4.8 % State and Local Government — 57.1 — — 57.1 1.1 % Other – Asset Backed — 1.3 — — 1.3 — % Subtotal – Fixed Income 0.1 3,171.3 — — 3,171.4 59.2 % Infrastructure (b) — — — 92.1 92.1 1.7 % Real Estate (b) — — — 232.6 232.6 4.4 % Alternative Investments (b) — — — 448.8 448.8 8.4 % Cash and Cash Equivalents (b) — 64.3 — 53.4 117.7 2.2 % Other – Pending Transactions and Accrued Income (c) — — — (28.2) (28.2) (0.5) % Total $ 854.7 $ 3,235.6 $ — $ 1,262.6 $ 5,352.9 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (c) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2021: Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 474.0 $ — $ — $ — $ 474.0 23.2 % International 296.3 — — — 296.3 14.5 % Common Collective Trusts (a) — — — 265.0 265.0 13.0 % Subtotal – Equities 770.3 — — 265.0 1,035.3 50.7 % Fixed Income: Common Collective Trust – Debt (a) — — — 167.7 167.7 8.2 % United States Government and Agency Securities — 222.4 — — 222.4 10.9 % Corporate Debt — 233.2 — — 233.2 11.4 % Foreign Debt — 39.8 — — 39.8 2.0 % State and Local Government 91.9 13.6 — — 105.5 5.1 % Subtotal – Fixed Income 91.9 509.0 — 167.7 768.6 37.6 % Trust Owned Life Insurance: International Equities — 23.4 — — 23.4 1.1 % United States Bonds — 171.3 — — 171.3 8.4 % Subtotal – Trust Owned Life Insurance — 194.7 — — 194.7 9.5 % Cash and Cash Equivalents (a) 33.0 — — 6.7 39.7 1.9 % Other – Pending Transactions and Accrued Income (b) — — — 6.0 6.0 0.3 % Total $ 895.2 $ 703.7 $ — $ 445.4 $ 2,044.3 100.0 % (a) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Accumulated Benefit Obligation The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 3,827.4 $ 315.4 $ 470.1 $ 443.8 $ 344.1 $ 179.1 $ 234.0 Nonqualified Pension Plans 55.6 2.5 0.3 1.2 0.1 1.2 1.1 Total as of December 31, 2022 $ 3,883.0 $ 317.9 $ 470.4 $ 445.0 $ 344.2 $ 180.3 $ 235.1 Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,822.5 $ 391.4 $ 597.0 $ 575.2 $ 440.0 $ 232.1 $ 291.4 Nonqualified Pension Plans 69.7 3.3 0.4 1.2 0.3 1.5 1.3 Total as of December 31, 2021 $ 4,892.2 $ 394.7 $ 597.4 $ 576.4 $ 440.3 $ 233.6 $ 292.7 Obligations in Excess of Fair Values The tables below show the underfunded pension plans that had obligations in excess of plan assets. Projected Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 61.5 $ 2.7 $ 0.6 $ 1.6 $ 0.3 $ 1.5 $ 250.7 Fair Value of Plan Assets — — — — — — 231.3 Underfunded Projected Benefit Obligation as of December 31, 2022 $ (61.5) $ (2.7) $ (0.6) $ (1.6) $ (0.3) $ (1.5) $ (19.4) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 78.4 $ 3.6 $ 0.8 $ 1.9 $ 0.7 $ 1.9 $ 317.7 Fair Value of Plan Assets — — — — — — 308.3 Underfunded Projected Benefit Obligation as of December 31, 2021 $ (78.4) $ (3.6) $ (0.8) $ (1.9) $ (0.7) $ (1.9) $ (9.4) Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Accumulated Benefit Obligation $ 55.6 $ 2.5 $ 0.3 $ 1.2 $ 0.1 $ 1.2 $ 235.1 Fair Value of Plan Assets — — — — — — 231.3 Underfunded Accumulated Benefit Obligation as of December 31, 2022 $ (55.6) $ (2.5) $ (0.3) $ (1.2) $ (0.1) $ (1.2) $ (3.8) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Accumulated Benefit Obligation $ 69.7 $ 3.3 $ 0.4 $ 1.2 $ 0.3 $ 1.5 $ 1.3 Fair Value of Plan Assets — — — — — — — Underfunded Accumulated Benefit Obligation as of December 31, 2021 $ (69.7) $ (3.3) $ (0.4) $ (1.2) $ (0.3) $ (1.5) $ (1.3) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded non-qualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2023: Company Pension Plans OPEB (in millions) AEP $ 6.3 $ 3.1 AEP Texas 0.4 0.1 APCo — 1.6 I&M 0.1 — PSO 0.1 — SWEPCo 0.1 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2023 $ 369.0 $ 35.4 $ 43.7 $ 38.1 $ 32.3 $ 19.2 $ 24.2 2024 373.6 36.3 43.6 39.8 31.9 18.9 25.1 2025 368.8 35.2 42.5 40.7 32.4 19.0 25.3 2026 369.6 35.0 43.0 40.4 32.0 19.2 25.5 2027 364.3 32.6 41.8 41.0 31.6 18.4 25.4 Years 2028 to 2032, in Total 1,702.3 138.9 202.1 196.4 146.0 81.1 107.9 OPEB Benefit Payments AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2023 $ 116.0 $ 9.1 $ 19.0 $ 14.9 $ 12.6 $ 6.7 $ 7.5 2024 117.6 9.5 19.3 15.0 12.6 6.9 7.8 2025 126.9 10.4 20.5 16.1 13.5 7.4 8.5 2026 127.4 10.6 20.4 16.3 13.4 7.3 8.6 2027 126.8 10.6 20.3 16.1 13.3 7.1 8.5 Years 2028 to 2032, in Total 604.0 48.5 95.8 75.1 62.3 32.2 41.2 OPEB Medicare AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2023 $ 0.2 $ — $ 0.1 $ — $ — $ — $ — 2024 0.3 — 0.1 — — — — 2025 0.3 — 0.1 — — — — 2026 0.3 — 0.1 — — — — 2027 0.3 — 0.1 — — — — Years 2028 to 2032, in Total 1.6 — 0.5 — — — — 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 Years Ended December 31, 20

Business Segments

Business Segments	12 Months Ended
Business Segments	Dec. 31, 2022
Business Segments	9. 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 standard service offer customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs. Generation & Marketing • Contracted renewable energy investments and management services. • Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP. • Competitive generation in PJM. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2022, 2021 and 2020 and reportable segment balance sheet information as of December 31, 2022 and 2021. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) (as adjusted) 2022 Revenues from: External Customers $ 11,292.8 $ 5,489.6 $ 357.5 $ 2,448.9 $ 50.7 $ — $ 19,639.5 Other Operating Segments 184.7 22.4 1,319.5 18.0 59.2 (1,603.8) — Total Revenues $ 11,477.5 $ 5,512.0 $ 1,677.0 $ 2,466.9 $ 109.9 $ (1,603.8) $ 19,639.5 Loss on the Expected Sale of the Kentucky Operations $ — $ — $ — $ — $ 363.3 $ — $ 363.3 Asset Impairments and Other Related Charges 24.9 — — — 23.9 — 48.8 Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset (37.0) — — — — — (37.0) Gain on Sale of Mineral Rights — — — (116.3) — — (116.3) Depreciation and Amortization 2,007.2 746.7 355.0 93.0 0.9 — 3,202.8 Interest Expense 650.9 328.0 169.3 51.8 308.9 (112.8) 1,396.1 Income Tax Expense (Benefit) (93.8) 116.9 193.6 (83.1) (128.2) — 5.4 Equity Earnings (Loss) of Unconsolidated Subsidiaries 1.4 0.6 83.4 (192.4) (2.4) — (109.4) Net Income (Loss) $ 1,296.2 $ 595.7 $ 676.8 $ 274.5 $ (537.6) $ — $ 2,305.6 Gross Property Additions $ 4,164.6 $ 2,177.3 $ 1,470.8 $ 69.2 $ 25.9 $ (28.8) $ 7,879.0 Total Assets $ 49,761.8 $ 22,920.2 $ 15,215.8 $ 4,520.1 $ 6,768.4 (b) $ (5,783.0) (c) $ 93,403.3 Investments in Equity Method Investees $ 10.1 $ 3.0 $ 858.3 $ 337.6 $ 67.7 $ — $ 1,276.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2021 Revenues from: External Customers $ 9,852.2 $ 4,464.1 $ 351.1 $ 2,108.3 $ 16.3 $ — $ 16,792.0 Other Operating Segments 146.3 28.8 1,175.1 55.4 55.9 (1,461.5) — Total Revenues $ 9,998.5 $ 4,492.9 $ 1,526.2 $ 2,163.7 $ 72.2 $ (1,461.5) $ 16,792.0 Asset Impairments and Other Related Charges $ 11.6 $ — $ — $ — $ — $ — $ 11.6 Depreciation and Amortization 1,747.6 690.3 306.0 80.9 0.9 — 2,825.7 Interest Expense 574.2 300.9 146.3 15.6 180.8 (18.7) 1,199.1 Income Tax Expense (Benefit) (11.2) 77.5 159.6 (48.8) (61.6) — 115.5 Equity Earnings (Loss) of Unconsolidated Subsidiaries 3.4 — 75.0 (10.6) 23.9 — 91.7 Net Income (Loss) $ 1,116.7 $ 543.4 $ 682.0 $ 210.2 $ (64.2) $ — $ 2,488.1 Gross Property Additions $ 2,963.1 $ 1,766.0 $ 1,468.6 $ 232.8 $ 25.5 $ (29.2) $ 6,426.8 Total Assets $ 46,974.2 $ 21,120.2 $ 13,873.3 $ 4,263.6 $ 5,846.5 (b) $ (4,409.1) (c) $ 87,668.7 Investments in Equity Method Investees $ 33.5 $ 2.5 $ 830.4 $ 487.8 $ 93.3 $ — $ 1,447.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2020 Revenues from: External Customers $ 8,753.2 $ 4,238.7 $ 297.4 $ 1,621.0 $ 8.2 $ — $ 14,918.5 Other Operating Segments 126.2 107.2 901.4 104.6 88.6 (1,328.0) — Total Revenues $ 8,879.4 $ 4,345.9 $ 1,198.8 $ 1,725.6 $ 96.8 $ (1,328.0) $ 14,918.5 Depreciation and Amortization $ 1,600.5 $ 751.1 $ 257.6 $ 72.8 $ 0.8 $ — $ 2,682.8 Interest Expense 565.0 289.2 133.2 24.0 196.4 (42.1) 1,165.7 Income Tax Expense (Benefit) (7.0) 29.7 130.8 (108.0) (5.0) — 40.5 Equity Earnings of Unconsolidated Subsidiaries 2.9 — 82.4 3.2 2.6 — 91.1 Net Income (Loss) $ 1,064.5 $ 496.4 $ 508.5 $ 216.9 $ (89.6) $ — $ 2,196.7 Gross Property Additions $ 2,291.2 $ 2,108.1 $ 1,649.3 $ 197.0 $ 16.0 $ (15.3) $ 6,246.3 Investments in Equity Method Investees $ 37.1 $ 2.1 $ 831.3 $ 467.0 $ 68.8 $ — $ 1,406.3 (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, interest expense and other nonallocated costs. (b) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (c) 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. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance-based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the years ended December 31, 2022, 2021 and 2020 and reportable segment balance sheet information as of December 31, 2022 and 2021. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo 2022 (in millions) Revenues from: External Customers $ 340.9 $ — $ — $ 340.9 Sales to AEP Affiliates 1,283.8 — — 1,283.8 Other Revenues (0.2) — — (0.2) Total Revenues $ 1,624.5 $ — $ — $ 1,624.5 Depreciation and Amortization $ 346.2 $ — $ — $ 346.2 Interest Income 0.7 177.8 (176.9) (a) 1.6 Allowance for Equity Funds Used During Construction 70.7 — — 70.7 Interest Expense 162.5 177.1 (176.9) (a) 162.7 Income Tax Expense 169.1 — — 169.1 Net Income $ 594.2 $ — (b) $ — $ 594.2 Gross Property Additions $ 1,468.3 $ — $ — $ 1,468.3 Total Assets $ 13,875.6 $ 4,817.4 (c) $ (4,878.8) (d) $ 13,814.2 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo 2021 (in millions) Revenues from: External Customers $ 315.1 $ — $ — $ 315.1 Sales to AEP Affiliates 1,153.9 — — 1,153.9 Other Revenues 0.3 — — 0.3 Total Revenues $ 1,469.3 $ — $ — $ 1,469.3 Depreciation and Amortization $ 297.3 $ — $ — $ 297.3 Interest Income 0.1 158.1 (157.7) (a) 0.5 Allowance for Equity Funds Used During Construction 67.2 — — 67.2 Interest Expense 141.2 157.7 (157.7) (a) 141.2 Income Tax Expense 144.1 — — 144.1 Net Income $ 591.5 $ 0.2 (b) $ — $ 591.7 Gross Property Additions $ 1,442.7 $ — $ — $ 1,442.7 Total Assets $ 12,564.3 $ 4,389.5 (c) $ (4,429.4) (d) $ 12,524.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo 2020 (in millions) Revenues from: External Customers $ 248.8 $ — $ — $ 248.8 Sales to AEP Affiliates 896.3 — — 896.3 Other Revenue 0.6 — — 0.6 Total Revenues $ 1,145.7 $ — $ — $ 1,145.7 Depreciation and Amortization $ 249.0 $ — $ — $ 249.0 Interest Income 0.9 149.6 (148.1) (a) 2.4 Allowance for Equity Funds Used During Construction 74.0 — — 74.0 Interest Expense 127.8 148.1 (148.1) (a) 127.8 Income Tax Expense 106.5 0.2 — 106.7 Net Income $ 422.3 $ 1.1 (b) $ — $ 423.4 Gross Property Additions $ 1,621.9 $ — $ — $ 1,621.9 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Primarily relates to Notes Receivable from the State Transcos. (d) Primarily relates to elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging

Derivatives and Hedging	12 Months Ended
Derivatives and Hedging	Dec. 31, 2022
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of certain 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 and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2022 Primary Risk Unit of AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 226.8 — 17.9 4.2 2.5 2.9 2.2 Natural Gas MMBtus 77.1 — 1.9 — — 1.9 2.1 Heating Oil and Gasoline Gallons 6.9 1.9 1.0 0.7 1.4 0.9 1.0 Interest Rate USD $ 99.9 $ — $ — $ — $ — $ — $ — Interest Rate on Long-term Debt USD $ 1,650.0 $ — $ — $ — $ — $ 200.0 $ — December 31, 2021 Primary Risk Unit of AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 287.9 — 33.1 13.6 2.7 11.9 3.4 Natural Gas MMBtus 34.1 — — — — 1.3 5.1 Heating Oil and Gasoline Gallons 7.4 1.9 1.1 0.7 1.5 0.8 1.0 Interest Rate USD $ 116.5 $ — $ — $ — $ — $ — $ — Interest Rate on Long-term Debt USD $ 950.0 $ — $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other 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 $481 million and $263 million as of December 31, 2022 and 2021, respectively. The amount of cash collateral from third-parties netted against short-term and long-term risk management assets were immaterial for the Registrant Subsidiaries as of December 31, 2022 and 2021. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities were immaterial for the Registrants as of December 31, 2022 and 2021. The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets. Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. AEP December 31, 2022 Risk Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 965.4 $ 212.2 $ 1.8 $ 1,179.4 $ (830.6) $ 348.8 Long-term Risk Management Assets 565.6 148.9 14.3 728.8 (444.7) 284.1 Total Assets 1,531.0 361.1 16.1 1,908.2 (1,275.3) 632.9 Current Risk Management Liabilities 663.8 60.4 41.4 765.6 (620.4) 145.2 Long-term Risk Management Liabilities 412.0 17.4 91.1 520.5 (175.3) 345.2 Total Liabilities 1,075.8 77.8 132.5 1,286.1 (795.7) 490.4 Total MTM Derivative Contract Net Assets (Liabilities) (d) $ 455.2 $ 283.3 $ (116.4) $ 622.1 $ (479.6) $ 142.5 December 31, 2021 Risk Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 520.9 $ 176.0 $ 1.2 $ 698.1 $ (497.7) $ 200.4 Long-term Risk Management Assets 370.5 89.1 — 459.6 (192.6) 267.0 Total Assets 891.4 265.1 1.2 1,157.7 (690.3) 467.4 Current Risk Management Liabilities 397.2 40.9 — 438.1 (362.6) 75.5 Long-term Risk Management Liabilities 243.9 16.7 38.1 298.7 (68.4) 230.3 Total Liabilities 641.1 57.6 38.1 736.8 (431.0) 305.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 250.3 $ 207.5 $ (36.9) $ 420.9 $ (259.3) $ 161.6 AEP Texas December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ — $ — $ — December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ (0.6) $ — Long-term Risk Management Assets — — — Total Assets 0.6 (0.6) — Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.6 $ (0.6) $ — APCo December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 69.3 $ (0.2) $ 69.1 Long-term Risk Management Assets 0.7 (0.7) — Total Assets 70.0 (0.9) 69.1 Current Risk Management Liabilities 4.1 (0.5) 3.6 Long-term Risk Management Liabilities 0.7 (0.6) 0.1 Total Liabilities 4.8 (1.1) 3.7 Total MTM Derivative Contract Net Assets (d) $ 65.2 $ 0.2 $ 65.4 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 47.5 $ (5.5) $ 42.0 Long-term Risk Management Assets 0.2 (0.2) — Total Assets 47.7 (5.7) 42.0 Current Risk Management Liabilities 7.2 (6.4) 0.8 Long-term Risk Management Liabilities 0.2 (0.2) — Total Liabilities 7.4 (6.6) 0.8 Total MTM Derivative Contract Net Assets $ 40.3 $ 0.9 $ 41.2 I&M December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 16.0 $ (0.8) $ 15.2 Long-term Risk Management Assets 0.5 (0.3) 0.2 Total Assets 16.5 (1.1) 15.4 Current Risk Management Liabilities 0.9 (0.9) — Long-term Risk Management Liabilities 0.3 (0.3) — Total Liabilities 1.2 (1.2) — Total MTM Derivative Contract Net Assets (d) $ 15.3 $ 0.1 $ 15.4 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 11.1 $ (7.8) $ 3.3 Long-term Risk Management Assets 0.2 (0.2) — Total Assets 11.3 (8.0) 3.3 Current Risk Management Liabilities 14.8 (9.8) 5.0 Long-term Risk Management Liabilities 0.2 (0.2) — Total Liabilities 15.0 (10.0) 5.0 Total MTM Derivative Contract Net Assets (Liabilities) $ (3.7) $ 2.0 $ (1.7) OPCo December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 2.1 (0.3) 1.8 Long-term Risk Management Liabilities 37.9 — 37.9 Total Liabilities 40.0 (0.3) 39.7 Total MTM Derivative Net Assets (Liabilities) (d) $ (40.0) $ 0.3 $ (39.7) December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ (0.5) $ — Long-term Risk Management Assets — — — Total Assets 0.5 (0.5) — Current Risk Management Liabilities 6.7 — 6.7 Long-term Risk Management Liabilities 85.8 — 85.8 Total Liabilities 92.5 — 92.5 Total MTM Derivative Contract Net Liabilities $ (92.0) $ (0.5) $ (92.5) PSO December 31, 2022 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) Interest Rate (a) (in millions) Current Risk Management Assets $ 24.1 $ 1.6 $ 25.7 $ (0.4) $ 25.3 Long-term Risk Management Assets — — — — — Total Assets 24.1 1.6 25.7 (0.4) 25.3 Current Risk Management Liabilities 2.1 — 2.1 (0.5) 1.6 Long-term Risk Management Liabilities — — — — — Total Liabilities 2.1 — 2.1 (0.5) 1.6 Total MTM Derivative Contract Net Assets (d) $ 22.0 $ 1.6 $ 23.6 $ 0.1 $ 23.7 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 12.4 $ (0.3) $ 12.1 Long-term Risk Management Assets — — — Total Assets 12.4 (0.3) 12.1 Current Risk Management Liabilities 3.7 — 3.7 Long-term Risk Management Liabilities — — — Total Liabilities 3.7 — 3.7 Total MTM Derivative Contract Net Assets (Liabilities) $ 8.7 $ (0.3) $ 8.4 SWEPCo December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 16.8 $ (0.4) $ 16.4 Long-term Risk Management Assets — — — Total Assets 16.8 (0.4) 16.4 Current Risk Management Liabilities 2.0 (0.6) 1.4 Long-term Risk Management Liabilities — — — Total Liabilities 2.0 (0.6) 1.4 Total MTM Derivative Contract Net Assets (d) $ 14.8 $ 0.2 $ 15.0 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 10.1 $ (0.3) $ 9.8 Long-term Risk Management Assets 1.1 — 1.1 Total Assets 11.2 (0.3) 10.9 Current Risk Management Liabilities 2.1 — 2.1 Long-term Risk Management Liabilities — — — Total Liabilities 2.1 — 2.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 9.1 $ (0.3) $ 8.8 (a) Derivative instruments within these categories are disclosed as 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. (d) Increase in amounts as of December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs. The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2022 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 11.1 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 313.8 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.5 10.6 — — — Purchased Electricity for Resale 5.0 — 4.5 0.1 — 0.2 — Other Operation 4.8 1.5 0.4 0.5 0.8 0.6 0.8 Maintenance 6.7 1.8 0.9 0.6 1.2 0.8 1.1 Regulatory Assets (a) 52.6 0.1 (0.1) (0.8) 52.1 3.6 (2.1) Regulatory Liabilities (a) 299.7 (0.6) 82.4 8.6 3.7 98.5 77.9 Total Gain on Risk Management Contracts (b) $ 693.7 $ 2.8 $ 88.6 $ 19.6 $ 57.8 $ 103.7 $ 77.7 Year Ended December 31, 2021 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (0.6) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 169.1 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (0.5) (0.1) — — — Purchased Electricity for Resale 2.0 — 1.8 — — — — Other Operation 2.8 0.8 0.3 0.3 0.5 0.3 0.4 Maintenance 3.4 1.0 0.5 0.3 0.6 0.4 0.5 Regulatory Assets (a) (9.1) — (2.7) (14.8) 10.0 (3.6) 3.6 Regulatory Liabilities (a) 156.4 0.2 55.9 (3.9) — 48.9 37.0 Total Gain (Loss) on Risk Management Contracts $ 324.0 $ 2.0 $ 55.3 $ (18.2) $ 11.1 $ 46.0 $ 41.5 Year Ended December 31, 2020 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.8 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 9.5 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.4 0.1 — — 0.1 Purchased Electricity for Resale 1.4 — 1.2 0.1 — — — Other Operation (2.0) (0.6) (0.2) (0.2) (0.3) (0.2) (0.3) Maintenance (2.9) (0.8) (0.4) (0.3) (0.5) (0.3) (0.4) Regulatory Assets (a) (4.8) — — (0.1) (6.6) — 1.4 Regulatory Liabilities (a) 114.9 0.4 20.3 12.4 12.4 39.1 20.2 Total Gain (Loss) on Risk Management Contracts $ 116.9 $ (1.0) $ 21.3 $ 12.0 $ 5.0 $ 38.6 $ 21.0 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. (b) Increase in amounts for the year ended December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs. 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 line item on the statements of income as that of the associated risk being hedged. 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 Liabilities Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (in millions) Long-term Debt (a) (b) $ (855.5) $ (952.3) $ 89.7 $ (8.5) (a) Amounts included on the Balance Sheet within Current and Noncurrent Liabilities line items Long-term Debt Due within One Year and Long-term Debt, respectively. (b) Amounts include $(38) million and $(46) million as of December 31, 2022 and 2021, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued. The pretax effects of fair value hedge accounting on income were as follows: Years Ended December 31, 2022 2021 2020 (in millions) Gain (Loss) on Interest Rate Contracts: Fair Value Hedging Instruments (a) $ (90.4) $ (35.5) $ 41.1 Fair Value Portion of Long-term Debt (a) 90.4 35.5 (41.1) (a) Gain (Loss) is included in Interest Expense on the statements of income. In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statements of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 in Interest Expense on the statements of income. Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo) For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2022, 2021 and 2020, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the years ended 2022, 2021 and 2020, AEP applied cash flow hedging to outstanding interest rate derivatives. During the years ended 2021 and 2020, APCo applied cash flow hedging to outstanding interest rate derivatives. During the year ended 2022, PSO applied cash flow hedging to outstanding interest rate derivatives. During the years ended 2022, 2021 and 2020, the other Registrant Subsidiaries did not have outstanding interest rate derivatives. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income. Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2022 December 31, 2021 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Gain (Loss) Net of Tax $ 223.5 $ 0.3 $ 163.7 $ (21.3) Portion Expected to be Reclassed to Net Income During the Next Twelve Months 119.9 0.3 106.7 (3.3) As of December 31, 2022 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 99 months and 96 months for commodity and interest rate hedges, respectively. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2022 December 31, 2021 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 $ (0.3) $ (0.2) $ (1.3) $ (1.1) APCo 6.7 0.8 7.5 0.8 I&M (5.1) (0.6) (6.7) (1.6) PSO 1.3 0.1 — — SWEPCo 1.1 0.2 1.2 0.1 The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Credit-Risk-Related Contingent Features 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. AEP had derivative contracts with collateral triggering events in a net liability position with a total exposure of $2 million and $9 million as of December 31, 2022 and 2021, respectively. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2022 and 2021. Cross-Acceleration Triggers Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $127 million and $40 million as of December 31, 2022 and 2021, respectively. There was no cash collateral posted as of December 31, 2022 and 2021, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2022 and 2021. Cross-Default Triggers (Applies to AEP, APCo, I&M, PSO 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. AEP had derivative liabilities subject to cross-default provisions in a net liability position of $217 million and $76 million as of December 31, 2022 and 2021, respectively, after considering contractual netting arrangements. There was no cash collateral posted as of December 31, 2022 and 2021, respectively. If a cross-default provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries’ derivative contracts with cross-default provisions outstanding as of December 31, 2022 and 2021 were not material.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2022
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly-traded securities issued by AEP. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2022 2021 Company Book Value Fair Value Book Value Fair Value (in millions) AEP (a) $ 36,801.0 $ 32,915.9 $ 34,557.6 $ 38,789.3 AEP Texas 5,657.8 5,045.8 5,180.8 5,663.8 AEPTCo 4,782.8 3,940.5 4,343.9 4,968.2 APCo 5,410.5 5,079.2 4,938.9 6,037.1 I&M 3,260.8 2,929.0 3,195.0 3,748.0 OPCo 2,970.3 2,516.6 2,968.5 3,437.5 PSO 1,912.8 1,635.8 1,913.5 2,163.7 SWEPCo 3,391.6 2,870.9 3,395.2 3,792.9 (a) The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $877 million and $1.7 billion as of December 31, 2022 and 2021, respectively. See “Equity Units” section of Note 14 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 for additional information. The following is a summary of Other Temporary Investments and Restricted Cash: December 31, 2022 Gross Gross Unrealized Unrealized Fair Other Temporary Investments and Restricted Cash Cost Gains Losses Value (in millions) Restricted Cash (a) $ 47.1 $ — $ — $ 47.1 Other Cash Deposits 9.0 — — 9.0 Fixed Income Securities – Mutual Funds (b) 152.4 — (8.3) 144.1 Equity Securities – Mutual Funds 15.1 19.4 — 34.5 Total Other Temporary Investments and Restricted Cash $ 223.6 $ 19.4 $ (8.3) $ 234.7 December 31, 2021 Gross Gross Unrealized Unrealized Fair Other Temporary Investments and Restricted Cash Cost Gains Losses Value (in millions) Restricted Cash (a) $ 48.0 $ — $ — $ 48.0 Other Cash Deposits 10.0 — — 10.0 Fixed Income Securities – Mutual Funds (b) 154.3 0.5 — 154.8 Equity Securities – Mutual Funds 19.7 35.9 — 55.6 Total Other Temporary Investments and Restricted Cash $ 232.0 $ 36.4 $ — $ 268.4 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Years Ended December 31, 2022 2021 2020 (in millions) Proceeds from Investment Sales $ 30.2 $ 15.0 $ 50.9 Purchases of Investments 18.8 26.9 41.6 Gross Realized Gains on Investment Sales 6.1 3.6 3.8 Gross Realized Losses on Investment Sales 1.3 — 0.2 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 for additional information. The following is a summary of nuclear trust fund investments: December 31, 2022 2021 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 21.2 $ — $ — $ 84.7 $ — $ — Fixed Income Securities: United States Government 1,123.8 (3.1) (18.8) 1,156.4 66.3 (7.9) Corporate Debt 61.6 (7.0) (9.6) 76.7 6.7 (2.1) State and Local Government 3.3 0.1 (0.1) 7.3 0.4 (0.1) Subtotal Fixed Income Securities 1,188.7 (10.0) (28.5) 1,240.4 73.4 (10.1) Equity Securities - Domestic (a) 2,131.3 1,477.3 — 2,541.9 1,901.3 — Spent Nuclear Fuel and Decommissioning Trusts $ 3,341.2 $ 1,467.3 $ (28.5) $ 3,867.0 $ 1,974.7 $ (10.1) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $1.5 billion and $1.9 billion and unrealized losses of $6 million and $4 million as of December 31, 2022 and 2021, respectively. The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2022 2021 2020 (in millions) Proceeds from Investment Sales $ 2,713.6 $ 1,886.4 $ 1,593.4 Purchases of Investments 2,765.4 1,928.2 1,637.2 Gross Realized Gains on Investment Sales 52.4 103.2 26.4 Gross Realized Losses on Investment Sales 42.6 16.5 26.1 The base cost of fixed income securities was $1.2 billion and $1.2 billion as of December 31, 2022 and 2021, respectively. The base cost of equity securities was $654 million and $641 million as of December 31, 2022 and 2021, respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2022 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 365.2 After 1 year through 5 years 425.4 After 5 years through 10 years 203.0 After 10 years 195.1 Total $ 1,188.7 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1. The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments and Restricted Cash Restricted Cash $ 47.1 $ — $ — $ — $ 47.1 Other Cash Deposits (a) — — — 9.0 9.0 Fixed Income Securities – Mutual Funds 144.1 — — — 144.1 Equity Securities – Mutual Funds (b) 34.5 — — — 34.5 Total Other Temporary Investments and Restricted Cash 225.7 — — 9.0 234.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 15.0 1,197.5 314.4 (1,211.5) 315.4 Cash Flow Hedges: Commodity Hedges (c) — 332.6 26.7 (52.8) 306.5 Interest Rate Hedges — 11.0 — — 11.0 Total Risk Management Assets 15.0 1,541.1 341.1 (1,264.3) 632.9 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 11.3 — — 9.9 21.2 Fixed Income Securities: United States Government — 1,123.8 — — 1,123.8 Corporate Debt — 61.6 — — 61.6 State and Local Government — 3.3 — — 3.3 Subtotal Fixed Income Securities — 1,188.7 — — 1,188.7 Equity Securities – Domestic (b) 2,131.3 — — — 2,131.3 Total Spent Nuclear Fuel and Decommissioning Trusts 2,142.6 1,188.7 — 9.9 3,341.2 Total Assets $ 2,383.3 $ 2,729.8 $ 341.1 $ (1,245.4) $ 4,208.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 21.8 $ 870.9 $ 179.0 $ (731.9) $ 339.8 Cash Flow Hedges: Commodity Hedges (c) — 74.3 1.7 (52.8) 23.2 Fair Value Hedges — 127.4 — — 127.4 Total Risk Management Liabilities $ 21.8 $ 1,072.6 $ 180.7 $ (784.7) $ 490.4 AEP December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments and Restricted Cash Restricted Cash $ 48.0 $ — $ — $ — $ 48.0 Other Cash Deposits (a) — — — 10.0 10.0 Fixed Income Securities – Mutual Funds 154.8 — — — 154.8 Equity Securities – Mutual Funds (b) 55.6 — — — 55.6 Total Other Temporary Investments and Restricted Cash 258.4 — — 10.0 268.4 Risk Management Assets Risk Management Commodity Contracts (c) (f) 7.4 649.6 232.7 (643.9) 245.8 Cash Flow Hedges: Commodity Hedges (c) — 242.9 19.2 (41.7) 220.4 Fair Value Hedges — 1.2 — — 1.2 Total Risk Management Assets 7.4 893.7 251.9 (685.6) 467.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 77.7 — — 7.0 84.7 Fixed Income Securities: United States Government — 1,156.4 — — 1,156.4 Corporate Debt — 76.7 — — 76.7 State and Local Government — 7.3 — — 7.3 Subtotal Fixed Income Securities — 1,240.4 — — 1,240.4 Equity Securities – Domestic (b) 2,541.9 — — — 2,541.9 Total Spent Nuclear Fuel and Decommissioning Trusts 2,619.6 1,240.4 — 7.0 3,867.0 Other Investments (h) 28.8 14.9 — — 43.7 Total Assets $ 2,914.2 $ 2,149.0 $ 251.9 $ (668.6) $ 4,646.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 5.3 $ 485.9 $ 148.2 $ (384.6) $ 254.8 Cash Flow Hedges: Commodity Hedges (c) — 54.0 0.6 (41.7) 12.9 Fair Value Hedges — 38.1 — — 38.1 Total Risk Management Liabilities $ 5.3 $ 578.0 $ 148.8 $ (426.3) $ 305.8 AEP Texas December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 32.7 $ — $ — $ — $ 32.7 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 30.4 $ — $ — $ — $ 30.4 Risk Management Assets Risk Management Commodity Contracts (c) — 0.6 — (0.6) — Total Assets $ 30.4 $ 0.6 $ — $ (0.6) $ 30.4 APCo December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 14.4 $ — $ — $ — $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.7 69.4 (1.0) 69.1 Total Assets $ 14.4 $ 0.7 $ 69.4 $ (1.0) $ 83.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 4.6 $ 0.3 $ (1.4) $ 3.5 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 17.6 $ — $ — $ — $ 17.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 5.8 42.0 (5.8) 42.0 Total Assets $ 17.6 $ 5.8 $ 42.0 $ (5.8) $ 59.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 7.2 $ 0.3 $ (6.7) $ 0.8 I&M December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 11.3 $ 5.3 $ (1.2) $ 15.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 11.3 — — 9.9 21.2 Fixed Income Securities: United States Government — 1,123.8 — — 1,123.8 Corporate Debt — 61.6 — — 61.6 State and Local Government — 3.3 — — 3.3 Subtotal Fixed Income Securities — 1,188.7 — — 1,188.7 Equity Securities - Domestic (b) 2,131.3 — — — 2,131.3 Total Spent Nuclear Fuel and Decommissioning Trusts 2,142.6 1,188.7 — 9.9 3,341.2 Total Assets $ 2,142.6 $ 1,200.0 $ 5.3 $ 8.7 $ 3,356.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (1.3) $ — December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 3.8 $ 7.6 $ (8.1) $ 3.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 77.7 — — 7.0 84.7 Fixed Income Securities: United States Government — 1,156.4 — — 1,156.4 Corporate Debt — 76.7 — — 76.7 State and Local Government — 7.3 — — 7.3 Subtotal Fixed Income Securities — 1,240.4 — — 1,240.4 Equity Securities - Domestic (b) 2,541.9 — — — 2,541.9 Total Spent Nuclear Fuel and Decommissioning Trusts 2,619.6 1,240.4 — 7.0 3,867.0 Total Assets $ 2,619.6 $ 1,244.2 $ 7.6 $ (1.1) $ 3,870.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 6.7 $ 8.3 $ (10.0) $ 5.0 OPCo December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ — $ — $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 40.0 $ (0.3) $ 39.7 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ — $ (0.5) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 92.5 $ — $ 92.5 PSO December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 24.0 $ 1.3 $ 25.3 Cash Flow Hedges: Interest Rate Hedges — 1.6 — (1.6) — Total Assets $ — $ 1.6 $ 24.0 $ (0.3) $ 25.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.7 $ 0.3 $ (0.4) $ 1.6 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 12.2 $ (0.4) $ 12.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 3.7 $ 0.1 $ (0.1) $ 3.7 SWEPCo December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 2.2 $ 14.6 $ (0.4) $ 16.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.6 $ 0.4 $ (0.6) $ 1.4 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 11.0 $ (0.4) $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 2.1 $ 0.1 $ (0.1) $ 2.1 (a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly-traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(7) million in 2023; Level 2 matures $182 million in 2023, $134 million in periods 2024-2026, $10 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $128 million in 2023, $6 million in periods 2024-2026, $6 million in periods 2027-2028 and $(5) million in periods 2029-2033. 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, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025; $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. (h) See “Warrants Held in Investee” section of Note 10 in the 2021 Annual Report for additional information. The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2022 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2021 $ 103.1 $ 41.7 $ (0.7) $ (92.5) $ 12.1 $ 10.9 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 69.5 3.0 3.7 6.5 24.2 35.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (34.9) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 9.6 — — — — — Settlements (154.6) (44.7) (3.0) 0.3 (36.3) (45.0) Transfers into Level 3 (d) (e) 1.7 — — — — — Transfers out of Level 3 (e) 0.1 — — — — 6.9 Changes in Fair Value Allocated to Regulated Jurisdictions (f) 165.9 69.1 4.6 45.7 23.7 5.6 Balance as of December 31, 2022 $ 160.4 $ 69.1 $ 4.6 $ (40.0) $ 23.7 $ 14.2 Year Ended December 31, 2021 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 48.6 8.3 (0.1) 2.4 16.1 9.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (45.2) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 24.2 — — — — — Settlements (89.0) (28.0) (2.2) 6.3 (26.4) (15.5) Transfers into Level 3 (d) (e) (3.8) — — — — — Transfers out of Level 3 (e) (34.4) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 89.4 42.1 (0.5) 9.1 12.1 15.3 Balance as of December 31, 2021 $ 103.1 $ 41.7 $ (0.7) $ (92.5) $ 12.1 $ 10.9 Year Ended December 31, 2020 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2019 $ 109.9 $ 37.7 $ 5.8 $ (103.6) $ 15.8 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 39.5 13.2 2.5 (1.6) 11.9 2.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 35.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 13.8 — — — — — Settlements (113.1) (51.6) (8.6) 8.9 (27.6) (6.6) Transfers into Level 3 (d) (e) (3.8) — — — — — Transfers out of Level 3 (e) 5.6 0.7 0.4 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 26.1 19.3 2.0 (14.0) 10.2 4.0 Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6 (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) Included in cash flow hedges on the statements of comprehensive income. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: AEP December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ 204.0 $ 167.4 Discounted Cash Flow Forward Market Price $ 2.91 $ 187.34 $ 49.14 FTRs 137.1 13.3 Discounted Cash Flow Forward Market Price (36.45) 20.72 1.18 Total $ 341.1 $ 180.7 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (c) (in millions) Energy Contracts $ 164.4 $ 135.3 Discounted Cash Flow Forward Market Price (a) $ 10.30 $ 76.70 $ 37.11 Natural Gas Contracts 3.6 — Discounted Cash Flow Forward Market Price (b) 3.11 4.02 3.47 FTRs 83.9 13.5 Discounted Cash Flow Forward Market Price (a) (23.93) 26.38 0.86 Total $ 251.9 $ 148.8 APCo December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 69.4 $ 0.3 Discounted Cash Flow Forward Market Price $ (2.82) $ 18.88 $ 3.89 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 0.3 Discounted Cash Flow Forward Market Price $ 32.20 $ 56.54 $ 44.77 FTRs 42.0 — Discounted Cash Flow Forward Market Price (0.30) 26.38 2.63 Total $ 42.0 $ 0.3 I&M December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 5.3 $ 0.7 Discounted Cash Flow Forward Market Price $ 0.16 $ 18.79 $ 1.23 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 0.2 Discounted Cash Flow Forward Market Price $ 32.20 $ 56.54 $ 44.77 FTRs 7.6 8.1 Discounted Cash Flow Forward Market Price (5.45) 17.78 (0.12) Total $ 7.6 $ 8.3 OPCo December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 40.0 Discounted Cash Flow Forward Market Price $ 2.91 $ 187.34 $ 48.76 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 92.5 Discounted Cash Flow Forward Market Price $ 14.26 $ 52.98 $ 30.68 PSO December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 24.0 $ 0.3 Discounted Cash Flow Forward Market Price $ (36.45) $ 3.40 $ (7.55) December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 12.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (18.39) $ 1.87 $ (2.57) SWEPCo December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 14.6 $ 0.4 Discounted Cash Flow Forward Market Price $ (36.45) $ 3.40 $ (7.55) December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (c) (in millions) Natural Gas Contracts $ 3.6 $ — Discounted Cash Flow Forward Market Price (b) $ 3.11 $ 4.02 $ 3.47 FTRs 7.4 0.1 Discounted Cash Flow Forward Market Price (a) (18.39) 1.87 (2.57) Total $ 11.0 $ 0.1 (a) Represents market prices in dollars per MWh. (b) Represents market prices in dollars per MMBtu. (c) The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term. The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts, FTRs and Other Investments for the Registrants as of December 31, 2022 and 2021: Uncertainty of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2022
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Benefit) The details of the Registrants’ Income Tax Expense (Benefit) as reported are as follows: Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ 113.1 $ 29.0 $ 98.0 $ (61.0) $ 43.4 $ (27.0) $ (3.3) $ (32.3) Deferred (88.8) 41.4 46.0 86.6 (51.3) 73.3 (50.5) 13.4 Total Federal 24.3 70.4 144.0 25.6 (7.9) 46.3 (53.8) (18.9) State and Local: Current 26.6 2.2 8.8 (0.4) 10.9 (0.3) — (1.8) Deferred (45.5) — 16.3 (7.0) 1.2 (1.8) 4.6 (4.5) Total State and Local (18.9) 2.2 25.1 (7.4) 12.1 (2.1) 4.6 (6.3) Income Tax Expense (Benefit) $ 5.4 $ 72.6 $ 169.1 $ 18.2 $ 4.2 $ 44.2 $ (49.2) $ (25.2) Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (27.8) $ (1.2) $ 69.8 $ 5.0 $ 26.9 $ 6.8 $ (109.6) $ (16.7) Deferred 182.6 40.5 54.1 14.9 (35.5) 25.2 105.6 26.2 Total Federal 154.8 39.3 123.9 19.9 (8.6) 32.0 (4.0) 9.5 State and Local: Current 6.0 3.0 5.8 2.2 (0.6) (3.1) — 0.4 Deferred (45.3) 0.8 14.4 — (1.4) 5.5 8.1 (10.5) Total State and Local (39.3) 3.8 20.2 2.2 (2.0) 2.4 8.1 (10.1) Income Tax Expense (Benefit) $ 115.5 $ 43.1 $ 144.1 $ 22.1 $ (10.6) $ 34.4 $ 4.1 $ (0.6) Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (138.2) $ 5.2 $ 22.2 $ 21.4 $ 11.3 $ (26.6) $ (11.4) $ (13.6) Deferred 146.9 (15.4) 65.4 (27.1) (20.6) 74.0 8.3 19.6 Total Federal 8.7 (10.2) 87.6 (5.7) (9.3) 47.4 (3.1) 6.0 State and Local: Current (16.7) (0.1) 2.8 9.3 1.9 (5.4) 0.1 (8.2) Deferred 48.5 (0.9) 16.3 0.7 (0.1) 3.2 8.2 11.6 Total State and Local 31.8 (1.0) 19.1 10.0 1.8 (2.2) 8.3 3.4 Income Tax Expense (Benefit) $ 40.5 $ (11.2) $ 106.7 $ 4.3 $ (7.5) $ 45.2 $ 5.2 $ 9.4 The following are reconciliations for the Registrants between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported: AEP Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 2,305.6 $ 2,488.1 $ 2,196.7 Less: Equity Earnings – Dolet Hills (1.4) (3.4) (2.9) Income Tax Expense 5.4 115.5 40.5 Pretax Income $ 2,309.6 $ 2,600.2 $ 2,234.3 Income Taxes on Pretax Income at Statutory Rate (21%) $ 485.0 $ 546.0 $ 469.2 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 17.1 25.9 26.5 Permanent - Miscellaneous 11.5 (1.3) (9.7) Investment Tax Credit Amortization (14.3) (22.0) (18.8) Production Tax Credits (197.1) (98.8) (83.1) State and Local Income Taxes, Net (14.0) 39.4 25.1 Removal Costs (26.5) (20.0) (18.6) AFUDC (29.3) (30.6) (32.5) Tax Adjustments (a) — (55.1) — Tax Reform Excess ADIT Reversal (214.5) (255.6) (268.2) Federal Return to Provision (17.4) (1.6) (2.6) CARES Act — — (48.0) Other 4.9 (10.8) 1.2 Income Tax Expense $ 5.4 $ 115.5 $ 40.5 Effective Income Tax Rate 0.2 % 4.4 % 1.8 % (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements. AEP Texas Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 307.9 $ 289.8 $ 241.0 Income Tax Expense (Benefit) 72.6 43.1 (11.2) Pretax Income $ 380.5 $ 332.9 $ 229.8 Income Taxes on Pretax Income at Statutory Rate (21%) $ 79.9 $ 69.9 $ 48.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: State and Local Income Taxes, Net 1.7 2.4 (0.8) AFUDC (4.1) (4.5) (4.1) Parent Company Loss Benefit — (3.2) (4.5) Tax Reform Excess ADIT Reversal (5.5) (21.3) (47.9) Other 0.6 (0.2) (2.2) Income Tax Expense (Benefit) $ 72.6 $ 43.1 $ (11.2) Effective Income Tax Rate 19.1 % 12.9 % (4.9) % AEPTCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 594.2 $ 591.7 $ 423.4 Income Tax Expense 169.1 144.1 106.7 Pretax Income $ 763.3 $ 735.8 $ 530.1 Income Taxes on Pretax Income at Statutory Rate (21%) $ 160.3 $ 154.5 $ 111.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: State and Local Income Taxes, Net 19.8 19.8 15.1 AFUDC (14.8) (14.1) (15.5) Parent Company Loss Benefit — (18.3) (7.0) Other 3.8 2.2 2.8 Income Tax Expense $ 169.1 $ 144.1 $ 106.7 Effective Income Tax Rate 22.2 % 19.6 % 20.1 % APCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 394.2 $ 348.9 $ 369.7 Income Tax Expense 18.2 22.1 4.3 Pretax Income $ 412.4 $ 371.0 $ 374.0 Income Taxes on Pretax Income at Statutory Rate (21%) $ 86.6 $ 77.9 $ 78.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 4.7 11.7 12.7 State and Local Income Taxes, Net (5.9) 2.1 7.9 Removal Costs (9.8) (7.3) (5.7) AFUDC (3.7) (4.6) (4.5) Parent Company Loss Benefit — — (6.2) Tax Adjustments (a) — 4.5 — Tax Reform Excess ADIT Reversal (50.9) (60.5) (72.3) Federal Return to Provision (2.8) (1.6) (7.2) Other — (0.1) 1.1 Income Tax Expense $ 18.2 $ 22.1 $ 4.3 Effective Income Tax Rate 4.4 % 6.0 % 1.1 % (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements. I&M Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 324.7 $ 279.8 $ 284.8 Income Tax Expense (Benefit) 4.2 (10.6) (7.5) Pretax Income $ 328.9 $ 269.2 $ 277.3 Income Taxes on Pretax Income at Statutory Rate (21%) $ 69.1 $ 56.5 $ 58.2 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 2.9 3.5 1.6 Investment Tax Credit Amortization (3.1) (6.4) (4.5) State and Local Income Taxes, Net 9.6 (1.3) 1.5 Removal Costs (12.4) (9.7) (10.5) AFUDC (2.1) (2.7) (2.4) Parent Company Loss Benefit — (2.8) (6.4) Tax Reform Excess ADIT Reversal (54.0) (46.3) (46.8) Federal Return to Provision (6.2) (0.6) 1.8 Other 0.4 (0.8) — Income Tax Expense (Benefit) $ 4.2 $ (10.6) $ (7.5) Effective Income Tax Rate 1.3 % (3.9) % (2.7) % OPCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 287.8 $ 253.6 $ 271.4 Equity Earnings of Unconsolidated Subsidiaries (0.6) — — Income Tax Expense 44.2 34.4 45.2 Pretax Income $ 331.4 $ 288.0 $ 316.6 Income Taxes on Pretax Income at Statutory Rate (21%) $ 69.6 $ 60.5 $ 66.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 3.0 2.2 3.7 State and Local Income Taxes, Net (1.6) — (1.7) AFUDC (2.9) (2.3) (2.6) Tax Adjustments (a) — 8.9 — Tax Reform Excess ADIT Reversal (27.5) (32.6) (27.2) Federal Return to Provision 3.5 (1.2) 6.5 Other 0.1 (1.1) — Income Tax Expense $ 44.2 $ 34.4 $ 45.2 Effective Income Tax Rate 13.3 % 11.9 % 14.3 % (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements. PSO Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 167.6 $ 141.1 $ 123.0 Income Tax Expense (Benefit) (49.2) 4.1 5.2 Pretax Income $ 118.4 $ 145.2 $ 128.2 Income Taxes on Pretax Income at Statutory Rate (21%) $ 24.9 $ 30.5 $ 26.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Investment Tax Credit Amortization (1.6) (1.8) (2.1) Production Tax Credits (47.7) (6.0) — State and Local Income Taxes, Net 4.3 6.4 6.5 Parent Company Loss Benefit — — (0.2) Tax Reform Excess ADIT Reversal (25.4) (25.4) (25.5) Federal Return to Provision (3.7) 0.7 (0.5) Other — (0.3) 0.1 Income Tax Expense (Benefit) $ (49.2) $ 4.1 $ 5.2 Effective Income Tax Rate (41.6) % 2.8 % 4.1 % SWEPCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 294.3 $ 242.1 $ 183.7 Less: Equity Earnings – Dolet Hills (1.4) (3.4) (2.9) Income Tax Expense (Benefit) (25.2) (0.6) 9.4 Pretax Income $ 267.7 $ 238.1 $ 190.2 Income Taxes on Pretax Income at Statutory Rate (21%) $ 56.2 $ 50.0 $ 39.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 2.3 1.8 1.9 Depletion (4.0) (2.7) (3.4) Production Tax Credits (57.1) (7.2) — State and Local Income Taxes, Net (4.9) (8.0) 2.7 Parent Company Loss Benefit — — (5.6) Tax Reform Excess ADIT Reversal (14.8) (31.1) (21.9) Other (2.9) (3.4) (4.2) Income Tax Expense (Benefit) $ (25.2) $ (0.6) $ 9.4 Effective Income Tax Rate (9.4) % (0.3) % 4.9 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2022 2021 (in millions) Deferred Tax Assets $ 3,567.4 $ 3,347.1 Deferred Tax Liabilities (12,464.3) (11,991.2) Net Deferred Tax Liabilities $ (8,896.9) $ (8,644.1) Property Related Temporary Differences $ (7,788.1) $ (7,346.4) Amounts Due to Customers for Future Income Taxes 962.7 1,086.6 Deferred State Income Taxes (1,049.3) (1,211.8) Securitized Assets (98.9) (128.8) Regulatory Assets (865.2) (746.6) Accrued Nuclear Decommissioning (632.7) (743.2) Net Operating Loss Carryforward 132.4 303.2 Tax Credit Carryforward 612.0 440.1 Operating Lease Liability 142.9 116.3 Investment in Partnership (338.9) (392.1) Valuation Allowance (28.2) (25.0) Deferred Revenues 7.1 8.8 Postretirement Benefits 2.5 (46.2) All Other, Net 44.8 41.0 Net Deferred Tax Liabilities $ (8,896.9) $ (8,644.1) AEP Texas December 31, 2022 2021 (in millions) Deferred Tax Assets $ 177.0 $ 173.8 Deferred Tax Liabilities (1,321.2) (1,262.7) Net Deferred Tax Liabilities $ (1,144.2) $ (1,088.9) Property Related Temporary Differences $ (1,130.7) $ (1,060.2) Amounts Due to Customers for Future Income Taxes 111.0 110.0 Deferred State Income Taxes (36.6) (32.2) Securitized Transition Assets (65.0) (84.4) Regulatory Assets (48.9) (45.1) Operating Lease Liability 20.3 15.8 All Other, Net 5.7 7.2 Net Deferred Tax Liabilities $ (1,144.2) $ (1,088.9) AEPTCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 165.0 $ 161.2 Deferred Tax Liabilities (1,221.5) (1,139.5) Net Deferred Tax Liabilities $ (1,056.5) $ (978.3) Property Related Temporary Differences $ (1,081.5) $ (1,012.4) Amounts Due to Customers for Future Income Taxes 118.5 120.1 Deferred State Income Taxes (108.1) (97.0) Regulatory Assets (1.1) (1.3) Net Operating Loss Carryforward 5.5 8.1 Tax Credit Carryforward 0.2 0.1 Operating Lease Liability 0.3 0.1 Valuation Allowance (0.1) (0.1) All Other, Net 9.8 4.1 Net Deferred Tax Liabilities $ (1,056.5) $ (978.3) APCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 510.3 $ 495.1 Deferred Tax Liabilities (2,502.5) (2,299.8) Net Deferred Tax Liabilities $ (1,992.2) $ (1,804.7) Property Related Temporary Differences $ (1,509.8) $ (1,476.5) Amounts Due to Customers for Future Income Taxes 163.0 182.1 Deferred State Income Taxes (318.5) (288.8) Securitized Assets (33.9) (39.3) Regulatory Assets (301.2) (177.0) Operating Lease Liability 15.6 14.2 All Other, Net (7.4) (19.4) Net Deferred Tax Liabilities $ (1,992.2) $ (1,804.7) I&M December 31, 2022 2021 (in millions) Deferred Tax Assets $ 933.7 $ 1,072.2 Deferred Tax Liabilities (2,090.7) (2,172.4) Net Deferred Tax Liabilities $ (1,157.0) $ (1,100.2) Property Related Temporary Differences $ (398.0) $ (286.2) Amounts Due to Customers for Future Income Taxes 114.3 135.5 Deferred State Income Taxes (227.0) (222.0) Regulatory Assets (29.5) (23.6) Accrued Nuclear Decommissioning (632.7) (743.2) Operating Lease Liability 13.6 13.5 All Other, Net 2.3 25.8 Net Deferred Tax Liabilities $ (1,157.0) $ (1,100.2) OPCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 218.8 $ 204.4 Deferred Tax Liabilities (1,319.9) (1,205.3) Net Deferred Tax Liabilities $ (1,101.1) $ (1,000.9) Property Related Temporary Differences $ (1,133.8) $ (1,042.0) Amounts Due to Customers for Future Income Taxes 112.6 117.7 Deferred State Income Taxes (59.6) (58.8) Regulatory Assets (57.6) (39.8) Operating Lease Liability 15.5 17.2 All Other, Net 21.8 4.8 Net Deferred Tax Liabilities $ (1,101.1) $ (1,000.9) PSO December 31, 2022 2021 (in millions) Deferred Tax Assets $ 225.0 $ 170.0 Deferred Tax Liabilities (1,013.6) (952.3) Net Deferred Tax Liabilities $ (788.6) $ (782.3) Property Related Temporary Differences $ (763.3) $ (708.6) Amounts Due to Customers for Future Income Taxes 96.0 111.5 Deferred State Income Taxes (81.9) (83.2) Regulatory Assets (140.2) (228.0) Net Operating Loss Carryforward 25.8 111.4 Tax Credit Carryforward 54.3 6.6 All Other, Net 20.7 8.0 Net Deferred Tax Liabilities $ (788.6) $ (782.3) SWEPCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 374.9 $ 336.4 Deferred Tax Liabilities (1,464.6) (1,424.0) Net Deferred Tax Liabilities $ (1,089.7) $ (1,087.6) Property Related Temporary Differences $ (1,053.8) $ (989.6) Amounts Due to Customers for Future Income Taxes 146.2 154.8 Deferred State Income Taxes (208.7) (234.9) Regulatory Assets (114.1) (101.4) Net Operating Loss Carryforward 42.7 67.4 Tax Credit Carryforward 66.0 8.5 All Other, Net 32.0 7.6 Net Deferred Tax Liabilities $ (1,089.7) $ (1,087.6) Federal and State Income Tax Audit Status The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. AEP has agreed to extend the statute of limitations on the 2017 and 2018 tax returns to December 31, 2023, to allow time for the current IRS audit to be completed including a refund claim approval by the Congressional Joint Committee on Taxation. The statute of limitations for the 2019 return is set to naturally expire in 2023 as well. The current IRS audit and associated refund claim evolved from a net operating loss carryback to 2015 that originated in the 2017 return. AEP has received and agreed to two IRS proposed adjustments on the 2017 tax return, which were immaterial. The exam is nearly complete, and AEP is currently working with the IRS to submit the refund claim to the Congressional Joint Committee on Taxation for resolution and final approval. AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. Generally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity. Net Income Tax Operating Loss Carryforward As of December 31, 2022, AEP, AEPTCo, OPCo, PSO and SWEPCo have state net income tax operating loss carryforwards as indicated in the table below: State Net Income Tax Operating Loss Years of Company State/Municipality Carryforward Expiration (in millions) AEP Arkansas $ 224.4 2023 - 2032 AEP Colorado 82.6 NA AEP Illinois 52.4 2031 - 2041 AEP Kentucky 231.3 2030 - 2037 AEP Louisiana 586.8 NA AEP Michigan 58.7 2029 - 2031 AEP New Jersey 13.7 2036 - 2040 AEP New Mexico 22.9 NA AEP Ohio Municipal 1,257.7 2023 - 2027 AEP Oklahoma 943.3 2037 - 2037 AEP Pennsylvania 64.4 2030 - 2042 AEP Tennessee 77.7 2030 - 2037 AEP Virginia 11.2 2030 - 2037 AEP West Virginia 12.3 2029 - 2037 AEPTCo Oklahoma 33.0 2037 - 2037 OPCo Ohio Municipal 190.1 2024 - 2027 PSO Oklahoma 899.6 2037 - 2037 SWEPCo Arkansas 224.2 2023 - 2032 SWEPCo Louisiana 577.2 NA Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2017, 2019 and 2021 resulted in unused federal and state income tax credits. As of December 31, 2022, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2036 through 2041 and state tax credits will remain available indefinitely. Total Federal Total State Tax Credit Tax Credit Company Carryforward Carryforward (in millions) AEP $ 612.0 $ 39.2 AEP Texas 1.5 — AEPTCo 0.2 — APCo 2.0 — I&M 11.4 — OPCo 1.0 — PSO 54.3 39.2 SWEPCo 66.0 — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that it is more-likely-than-not that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective evidence evaluated includes whether AEP has a history of recognizing income, future reversals of existing temporary differences and tax planning strategies. Valuation allowance activity for the years ended December 31, 2022, 2021 and 2020 was not material. Uncertain Tax Positions The reconciliations of the beginning and ending amounts of unrecognized tax benefits for AEP and OPCo are presented below. The amount and activity of unrecognized tax benefits for the other Registrant Subsidiaries was immaterial for periods presented: AEP 2022 2021 2020 (in millions) Balance as of January 1, $ 14.3 $ 13.2 $ 24.1 Increase – Tax Positions Taken During a Prior Period 5.1 1.2 0.6 Decrease – Tax Positions Taken During a Prior Period — (3.2) (14.5) Increase – Tax Positions Taken During the Current Year 3.8 3.1 3.0 Decrease – Tax Positions Taken During the Current Year — — — Decrease – Settlements with Taxing Authorities — — — Decrease – Lapse of the Applicable Statute of Limitations — — — Balance as of December 31, $ 23.2 $ 14.3 $ 13.2 OPCo 2022 2021 2020 (in millions) Balance as of January 1, $ — $ 3.2 $ 8.4 Increase – Tax Positions Taken During a Prior Period 5.1 — — Decrease – Tax Positions Taken During a Prior Period — (3.2) (5.2) Increase – Tax Positions Taken During the Current Year — — — Decrease – Tax Positions Taken During the Current Year — — — Decrease – Settlements with Taxing Authorities — — — Decrease – Lapse of the Applicable Statute of Limitations — — — Balance as of December 31, $ 5.1 $ — $ 3.2 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for AEP as of December 31, 2022, 2021 and 2020 were $23 million, $14 million, and $12 million, respectively. Federal Tax Legislation In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions including a 5-year NOL carryback from years 2018-2020. In the third quarter of 2020, AEP requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million during the third quarter of 2020 primarily at the Generation & Marketing segment. AEP received the $95 million refund in the fourth quarter of 2021. Inflation Reduction Act In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. This legislation has no material impact on the current period financial statements. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition. In November 2022, the IRS released Notice 2022-61 addressing the Prevailing Wage and Apprenticeship Requirements (PWAR) tied to full value PTCs and ITCs for projects that begin construction on or after January 29, 2023. AEP’s future renewable energy projects that begin construction after this date will be required to, and expect to, satisfy the PWAR to receive full value ITCs and PTCs. In December 2022, the IRS released Notice 2023-7 addressing time sensitive issues related to the CAMT. The notice provided initial guidance that AEP can begin to rely on in 2023 and also stated that additional guidance is expected, of which AEP will continue to monitor and assess. Notably, the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includes tax depreciation that is capitalized to inventory under §263A and recovered as part of cost of goods sold, providing significant relief to AEP’s potential CAMT exposure. The enactment of the IRA will have future cash flow and income tax reporting considerations. AEP and subsidiaries expect to be applicable corporations beginning in 2023 and AEP expects to have CAMT cash tax payments beginning in 2024. CAMT cash taxes are expected to be offset by regulatory recovery, the utilization of tax credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP will present the gain or loss on sale of tax credits through income tax expense. Management believes this presentation provides consistency in financial statement reporting as it matches the originating income tax benefit of the tax credits. State Tax Legislation In April 2021, West Virginia enacted House Bill (HB) 2026. HB 2026 changes the state income tax apportionment formula from a ratio that includes property, payroll and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. HB 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property. During 2021, AEP recorded $23 million in Income Tax Expense as a result of remeasuring West Virginia deferred taxes under the new apportionment methodology. The enacted legislation does not impact AEP Texas, PSO or SWEPCo. In May 2021, Oklahoma enacted HB 2960. HB 2960 reduces the Oklahoma corporate income tax rate from 6% to 4%. During 2021, AEP recorded an immaterial amount of Income Tax Benefit as a result of remeasuring Oklahoma deferred taxes at the lowered statutory tax rate of 4%. The enacted legislation does not impact APCo, I&M or OPCo. In November 2021, Louisiana approved Constitutional Amendment 2, thereby also enacting HB 292. HB 292 reduces the Louisiana corporate income tax rate from 8% to 7.5%. In the fourth quarter of 2021, AEP recorded an immaterial amount of Income Tax Expense as a result of remeasuring Louisiana deferred taxes at the lowered statutory tax rate of 7.5%. The enacted legislation does not impact AEP Texas, APCo, I&M, OPCo or PSO. In December 2021, Arkansas enacted HB 1001. HB 1001 reduces the Arkansas corporate income tax rate from 5.9% to 5.7%, with additional reductions to 5.3% contingent upon future events. In the fourth quarter of 2021, AEP recorded an immaterial amount of Income Tax Expense as a result of remeasuring Arkansas deferred taxes at the lowered statutory tax rate of 5.7%. The enacted legislation does not impact AEP Texas, APCo, I&M, OPCo or PSO. In August 2022, Arkansas enacted Senate Bill 1. Senate Bill 1 reduces the Arkansas corporate income tax rate from 5.7% to 5.3%. In the third quarter of 2022, AEP recorded an immaterial amount of Income Tax Expense as a result of remeasuring Arkansas deferred taxes at the lowered statutory tax rate of 5.3%. The enacted legislation does not impact AEP Texas, APCo, I&M, OPCo or PSO.

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2022
Leases	13. LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. AEP does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option. Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis. Operating lease rentals and finance lease amortization costs are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. The amortization costs related to the Rockport finance lease were charged to Depreciation and Amortization. Interest on finance lease liabilities is generally charged to Interest Expense. Lease costs associated with capital projects are included in Property, Plant and Equipment on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs were as follows: Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 157.5 $ 18.4 $ 1.1 $ 17.9 $ 29.5 $ 16.9 $ 11.8 $ 15.3 Finance Lease Cost: Amortization of Right-of-Use Assets 205.5 6.8 — 7.9 78.7 4.9 3.2 10.8 Interest on Lease Liabilities 13.4 1.3 — 2.0 3.1 0.8 0.6 2.1 Total Lease Rental Costs (a) $ 376.4 $ 26.5 $ 1.1 $ 27.8 $ 111.3 $ 22.6 $ 15.6 $ 28.2 Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 275.3 $ 18.4 $ 1.7 $ 19.3 $ 90.2 $ 19.0 $ 8.7 $ 12.1 Finance Lease Cost: Amortization of Right-of-Use Assets 74.7 6.7 — 7.7 12.9 4.9 3.2 11.0 Interest on Lease Liabilities 14.4 1.4 — 2.4 3.0 0.8 0.6 2.5 Total Lease Rental Costs (a) $ 364.4 $ 26.5 $ 1.7 $ 29.4 $ 106.1 $ 24.7 $ 12.5 $ 25.6 Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 279.6 $ 17.4 $ 2.6 $ 19.1 $ 101.5 $ 17.1 $ 7.8 $ 9.4 Finance Lease Cost: Amortization of Right-of-Use Assets 61.9 6.3 — 7.4 6.5 4.7 3.5 10.9 Interest on Lease Liabilities 15.4 1.5 — 2.7 3.1 0.9 0.7 2.2 Total Lease Rental Costs (a) $ 356.9 $ 25.2 $ 2.6 $ 29.2 $ 111.1 $ 22.7 $ 12.0 $ 22.5 (a) Excludes variable and short-term lease costs, which were immaterial. Supplemental information related to leases are shown in the tables below: December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo Weighted-Average Remaining Lease Term (years): Operating Leases 12.69 4.33 2.05 5.29 5.79 5.98 23.90 23.55 Finance Leases 4.61 5.39 0.00 4.25 4.76 5.27 6.02 4.13 Weighted-Average Discount Rate: Operating Leases 3.54 % 4.15 % 1.96 % 3.61 % 3.62 % 3.73 % 3.43 % 3.41 % Finance Leases 5.76 % 4.75 % — % 7.09 % 8.99 % 4.53 % 4.63 % 4.80 % December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo Weighted-Average Remaining Lease Term (years): Operating Leases 10.39 5.91 2.95 5.68 5.87 6.69 20.89 20.24 Finance Leases 2.95 5.51 0.00 4.97 2.10 5.54 6.18 4.53 Weighted-Average Discount Rate: Operating Leases 3.35 % 3.53 % 0.90 % 3.42 % 3.46 % 3.56 % 3.35 % 3.34 % Finance Leases 3.26 % 4.31 % — % 7.16 % 3.02 % 4.19 % 4.23 % 4.68 % Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows Used for Operating Leases $ 155.1 $ 18.3 $ 1.0 $ 17.9 $ 29.7 $ 17.5 $ 10.5 $ 13.7 Operating Cash Flows Used for Finance Leases 13.6 1.3 — 2.0 3.2 0.8 0.6 2.1 Financing Cash Flows Used for Finance Leases 309.5 6.8 — 7.9 130.7 4.9 3.2 10.8 Non-cash Acquisitions Under Operating Leases $ 191.4 $ 36.7 $ 1.7 $ 23.1 $ 19.1 $ 8.4 $ 46.0 $ 53.6 Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows Used for Operating Leases $ 279.9 $ 18.0 $ 1.6 $ 19.3 $ 92.9 $ 19.0 $ 8.7 $ 11.6 Operating Cash Flows Used for Finance Leases 14.3 1.4 — 2.4 2.9 0.8 0.6 2.5 Financing Cash Flows Used for Finance Leases 64.0 6.7 — 7.7 6.8 4.9 3.2 10.9 Non-cash Acquisitions Under Operating Leases $ 117.0 $ 4.4 $ 2.1 $ 4.2 $ 2.6 $ 4.2 $ 33.4 $ 42.9 The following tables show property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the balance sheets. Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months. December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Property, Plant and Equipment Under Finance Leases: Generation $ 120.9 $ — $ — $ 41.1 $ 28.0 $ — $ 0.6 $ 25.9 Other Property, Plant and Equipment 321.4 53.7 — 20.1 40.6 32.7 25.2 58.3 Total Property, Plant and Equipment 442.3 53.7 — 61.2 68.6 32.7 25.8 84.2 Accumulated Amortization 229.6 23.6 — 31.9 34.8 13.8 10.8 54.6 Net Property, Plant and Equipment Under Finance Leases $ 212.7 $ 30.1 $ — $ 29.3 $ 33.8 $ 18.9 $ 15.0 $ 29.6 Obligations Under Finance Leases: Noncurrent Liability $ 168.4 $ 23.1 $ — $ 21.6 $ 27.1 $ 14.2 $ 11.7 $ 31.3 Liability Due Within One Year 57.3 7.0 — 7.7 6.9 4.7 3.3 10.9 Total Obligations Under Finance Leases $ 225.7 $ 30.1 $ — $ 29.3 $ 34.0 $ 18.9 $ 15.0 $ 42.2 December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Property, Plant and Equipment Under Finance Leases: Generation $ 389.9 $ — $ — $ 42.8 $ 156.8 $ — $ 0.6 $ 34.3 Other Property, Plant and Equipment 328.1 50.7 — 20.4 42.1 32.1 23.9 55.7 Total Property, Plant and Equipment 718.0 50.7 — 63.2 198.9 32.1 24.5 90.0 Accumulated Amortization 225.0 19.9 — 27.5 38.2 12.8 9.2 47.8 Net Property, Plant and Equipment Under Finance Leases $ 493.0 $ 30.8 $ — $ 35.7 $ 160.7 $ 19.3 $ 15.3 $ 42.2 Obligations Under Finance Leases: Noncurrent Liability $ 198.2 $ 24.2 $ — $ 28.1 $ 31.7 $ 14.9 $ 12.3 $ 38.9 Liability Due Within One Year 305.3 6.6 — 7.6 130.5 4.4 3.0 10.8 Total Obligations Under Finance Leases $ 503.5 $ 30.8 $ — $ 35.7 $ 162.2 $ 19.3 $ 15.3 $ 49.7 December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Operating Lease Assets $ 645.5 $ 94.7 $ 2.7 $ 73.6 $ 64.3 $ 73.8 $ 106.1 $ 123.4 Obligations Under Operating Leases: Noncurrent Liability $ 552.5 $ 67.8 $ 1.5 $ 59.1 $ 48.9 $ 60.3 $ 99.3 $ 120.2 Liability Due Within One Year 113.6 28.6 1.3 15.0 16.0 13.5 8.9 8.4 Total Obligations Under Operating Leases $ 666.1 $ 96.4 $ 2.8 $ 74.1 $ 64.9 $ 73.8 $ 108.2 $ 128.6 December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Operating Lease Assets $ 589.0 $ 73.6 $ 2.0 $ 66.9 $ 63.5 $ 81.2 $ 68.9 $ 80.1 Obligations Under Operating Leases: Noncurrent Liability $ 501.4 $ 61.3 $ 1.3 $ 52.4 $ 48.9 $ 68.6 $ 62.2 $ 77.7 Liability Due Within One Year 99.8 14.0 0.9 15.1 15.5 13.1 6.9 8.1 Total Obligations Under Operating Leases $ 601.2 $ 75.3 $ 2.2 $ 67.5 $ 64.4 $ 81.7 $ 69.1 $ 85.8 Future minimum lease payments consisted of the following as of December 31, 2022: Finance Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) 2023 $ 67.9 $ 8.3 $ — $ 9.6 $ 9.2 $ 5.4 $ 3.8 $ 12.4 2024 71.5 7.2 — 8.8 12.1 4.6 3.3 16.5 2025 41.0 5.5 — 7.5 6.3 3.2 2.5 6.1 2026 25.0 4.4 — 2.9 3.9 2.6 2.2 2.8 2027 19.3 3.5 — 1.8 3.4 2.1 1.8 2.4 After 2027 32.6 5.5 — 2.8 7.6 3.4 3.7 5.6 Total Future Minimum Lease Payments 257.3 34.4 — 33.4 42.5 21.3 17.3 45.8 Less: Imputed Interest 31.6 4.3 — 4.1 8.5 2.4 2.3 3.6 Estimated Present Value of Future Minimum Lease Payments $ 225.7 $ 30.1 $ — $ 29.3 $ 34.0 $ 18.9 $ 15.0 $ 42.2 Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) 2023 $ 138.7 $ 32.3 $ 1.4 $ 17.5 $ 18.8 $ 16.4 $ 11.5 $ 14.4 2024 125.9 29.7 0.9 14.6 17.7 14.9 10.7 12.7 2025 86.7 13.1 0.4 11.8 9.2 13.2 9.5 11.4 2026 75.5 10.9 0.2 10.3 8.3 12.0 8.6 10.2 2027 65.6 8.3 — 9.1 7.5 10.7 7.8 8.8 After 2027 352.2 11.7 — 19.2 9.8 15.7 116.4 141.8 Total Future Minimum Lease Payments 844.6 106.0 2.9 82.5 71.3 82.9 164.5 199.3 Less: Imputed Interest 178.5 9.6 0.1 8.4 6.4 9.1 56.3 70.7 Estimated Present Value of Future Minimum Lease Payments $ 666.1 $ 96.4 $ 2.8 $ 74.1 $ 64.9 $ 73.8 $ 108.2 $ 128.6 Master Lease Agreements (Applies to all Registrants except AEPTCo) The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of December 31, 2022, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum (in millions) AEP $ 46.0 AEP Texas 11.1 APCo 6.1 I&M 4.4 OPCo 7.6 PSO 4.8 SWEPCo 5.3 AEPRO Boat and Barge Leases (Applies to AEP) In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of December 31, 2022, the maximum potential amount of future payments required under the guaranteed leases was $27 million. Under the terms of certain of the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, AEP is entitled to enter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor exercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have the ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the acquired assets for which it obtained title. As of December 31, 2022, AEP’s boat and barge lease guarantee liability was $2 million, of which $1 million was recorded in Other Current Liabilities and $1 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expects to continue their operations as normal. In March 2020, the bankruptcy court approved the party’s recapitalization plan. In April 2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP’s liability for future payments under these leases will be exercised within the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition. Lessor Activity The Registrants’ lessor activity was immaterial as of and for the twelve months ended December 31, 2022 and December 31, 2021, respectively.

Financing Activities

Financing Activities	12 Months Ended
Financing Activities	Dec. 31, 2022
Financing Activities	14. FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Common Stock (Applies to AEP) The following table is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2019 514,373,631 20,204,160 Issued 2,434,723 — Balance, December 31, 2020 516,808,354 20,204,160 Issued 7,607,821 — Balance, December 31, 2021 524,416,175 20,204,160 Issued 683,146 — Treasury Stock Reissued — (8,970,920) (a) Balance, December 31, 2022 525,099,321 11,233,240 (a) Reissued Treasury Stock used to fulfill share commitments related to AEP’s Equity Units. See “Equity Units” section below for additional information. ATM Program In 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. There were no issuances under the ATM program for the year ended December 31, 2022. Long-term Debt The following table details long-term debt outstanding: Weighted-Average Interest Rate Ranges as of Outstanding as of Interest Rate as of December 31, December 31, Company Maturity December 31, 2022 2022 2021 2022 2021 (in millions) AEP (as adjusted) Senior Unsecured Notes 2022-2052 3.98% 0.75%-8.13% 0.61%-8.13% $ 30,174.8 $ 28,185.7 Pollution Control Bonds (a) 2022-2036 (b) 2.74% 0.63%-4.55% 0.19%-4.55% 1,770.2 1,869.3 Notes Payable – Nonaffiliated (c) 2022-2032 4.29% 0.93%-6.37% 0.79%-6.37% 269.7 211.3 Securitization Bonds 2023-2029 (d) 2.91% 2.01%-3.77% 2.01%-3.77% 487.8 603.5 Spent Nuclear Fuel Obligation (e) 285.6 281.3 Junior Subordinated Notes (f) 2024-2027 2.35% 1.30%-3.88% 1.30%-3.88% 2,381.3 2,373.0 Other Long-term Debt 2022-2059 5.44% 1.15%-13.72% 0.76%-13.72% 1,431.6 1,033.5 Total Long-term Debt Outstanding $ 36,801.0 $ 34,557.6 AEP Texas Senior Unsecured Notes 2023-2052 4.06% 2.10%-6.76% 2.10%-6.76% $ 4,702.7 $ 4,135.5 Pollution Control Bonds 2023-2030 (b) 3.42% 0.90%-4.55% 0.90%-4.55% 440.2 439.9 Securitization Bonds 2024-2029 (d) 2.50% 2.06%-2.84% 2.06%-2.84% 314.4 404.7 Other Long-term Debt 2025-2059 5.67% 4.50%-5.67% 1.35%-4.50% 200.5 200.7 Total Long-term Debt Outstanding $ 5,657.8 $ 5,180.8 AEPTCo Senior Unsecured Notes 2023-2052 3.83% 2.75%-5.52% 2.75%-5.52% $ 4,782.8 $ 4,343.9 Total Long-term Debt Outstanding $ 4,782.8 $ 4,343.9 APCo Senior Unsecured Notes 2025-2050 4.68% 2.70%-7.00% 2.70%-7.00% $ 4,581.4 $ 4,083.7 Pollution Control Bonds (a) 2024-2036 (b) 2.74% 0.63%-3.80% 0.19%-2.75% 429.4 529.5 Securitization Bonds 2023-2028 (d) 3.67% 2.01%-3.77% 2.01%-3.77% 173.3 198.8 Other Long-term Debt 2023-2026 5.34% 4.84%-13.72% 1.24%-13.72% 226.4 126.9 Total Long-term Debt Outstanding $ 5,410.5 $ 4,938.9 I&M Senior Unsecured Notes 2023-2051 4.19% 3.20%-6.05% 3.20%-6.05% $ 2,597.3 $ 2,595.5 Pollution Control Bonds (a) 2025 (b) 2.49% 0.75%-3.05% 0.75%-3.05% 189.0 188.7 Notes Payable – Nonaffiliated (c) 2023-2027 4.26% 0.93%-5.93% 0.79%-1.24% 183.8 122.2 Spent Nuclear Fuel Obligation (e) 285.6 281.3 Other Long-term Debt 2025 6.00% 6.00% 6.00% 5.1 7.3 Total Long-term Debt Outstanding $ 3,260.8 $ 3,195.0 OPCo Senior Unsecured Notes 2030-2051 3.87% 1.63%-6.60% 1.63%-6.60% $ 2,969.7 $ 2,967.8 Other Long-term Debt 2028 1.15% 1.15% 1.15% 0.6 0.7 Total Long-term Debt Outstanding $ 2,970.3 $ 2,968.5 PSO Senior Unsecured Notes 2025-2051 3.74% 2.20%-6.63% 2.20%-6.63% $ 1,785.6 $ 1,785.5 Other Long-term Debt 2025-2027 5.69% 3.00%-5.75% 1.47%-3.00% 127.2 128.0 Total Long-term Debt Outstanding $ 1,912.8 $ 1,913.5 SWEPCo Senior Unsecured Notes 2026-2051 3.57% 1.65%-6.20% 1.65%-6.20% $ 3,297.6 $ 3,295.1 Notes Payable – Nonaffiliated (c) 2024-2032 5.38% 4.58%-6.37% 4.58%-6.37% 55.9 59.1 Other Long-term Debt 2028 4.68% 4.68% 4.68% 38.1 41.0 Total Long-term Debt Outstanding $ 3,391.6 $ 3,395.2 (a) For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (b) Certain Pollution Control Bonds are subject to redemption earlier than the maturity date. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date. (e) Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information. (f) See “Equity Units” section below for additional information. As of December 31, 2022, outstanding long-term debt was payable as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) 2023 $ 2,486.4 $ 278.5 $ 60.0 $ 251.8 $ 341.8 $ 0.1 $ 0.5 $ 6.2 2024 1,590.2 (a) 96.0 95.0 113.5 56.4 0.1 0.6 6.2 2025 3,253.9 (b) 524.5 90.0 673.3 220.5 0.1 250.6 6.2 2026 1,754.0 75.0 425.0 30.9 8.5 0.1 50.6 906.2 2027 2,251.9 25.6 — 355.6 1.7 0.1 0.3 6.2 After 2027 25,773.8 4,706.4 4,166.0 4,031.8 2,660.6 3,000.1 1,625.0 2,488.2 Principal Amount 37,110.2 5,706.0 4,836.0 5,456.9 3,289.5 3,000.6 1,927.6 3,419.2 Unamortized Discount, Net and Debt Issuance Costs (309.2) (48.2) (53.2) (46.4) (28.7) (30.3) (14.8) (27.6) Total Long-term Debt Outstanding $ 36,801.0 $ 5,657.8 $ 4,782.8 $ 5,410.5 $ 3,260.8 $ 2,970.3 $ 1,912.8 $ 3,391.6 (a) Amount includes $805 million of Junior Subordinated Notes. See “Equity Units” section below for additional information. (b) Amount includes $850 million of Junior Subordinated Notes. See “Equity Units” section below for additional information. Long-term Debt Subsequent Events In January and February 2023, I&M retired $8 million and $8 million, respectively, of Notes Payable related to DCC Fuel. In January 2023, PSO issued $475 million of 5.25% Senior Unsecured Notes due in 2033. In February 2023, AEP Texas retired $12 million of Securitization Bonds. In February 2023, APCo retired $13 million of Securitization Bonds. Equity Units (Applies to AEP) 2020 Equity Units In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. The proceeds were used to support AEP’s overall capital expenditure plans. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settles after three years in August 2023. The notes are expected to be remarketed in 2023, at which time the interest rate will reset at the then-current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%. Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment): • If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract. • If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50. • If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract. A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes. At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per-share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 10,205,100 shares (subject to an anti-dilution adjustment). 2019 Equity Units In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settled after three years in 2022. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP issued 8,970,920 shares of AEP common stock and received proceeds totaling $805 million under the settlement of the forward equity purchase contract. AEP common stock held in treasury was used to settle the forward equity purchase contract. 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 1.9% of consolidated tangible net assets as of December 31, 2022. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreement. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2022, the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $16.2 billion. The Federal Power Act restriction limits the ability of the AEP subsidiaries owning hydroelectric generation to pay dividends out of retained earnings. Additionally, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2022, the amount of any such restrictions were as follows: AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Restricted Retained Earnings $ 3,023.0 (a) $ 1,105.7 $ — $ 543.1 $ 688.2 $ — $ — $ 373.0 (a) Includes the restrictions of consolidated and non-consolidated subsidiaries. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. As of December 31, 2022, AEP had $8.1 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.6 billion, $1.5 billion and $1.4 billion of dividends to common shareholders for the years ended December 31, 2022, 2021 and 2020, respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. As of December 31, 2022, AEP had $5 billion in revolving credit facilities to support its commercial paper program. Securitized Debt for Receivables, for the year ended 2022, had a weighted-average interest rate of 1.84% and a maximum amount outstanding of $750 million. The commercial paper program, for the year ended 2022, had a weighted-average interest rate of 2.74% and a maximum amount outstanding of $2.9 billion. AEP’s outstanding short-term debt was as follows: December 31, 2022 2021 Company Type of Debt Outstanding Interest Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 4.67 % $ 750.0 0.19 % AEP Commercial Paper 2,862.2 4.80 % 1,364.0 0.34 % AEP Term Loan — — % 500.0 0.81 % AEP Term Loan 125.0 5.17 % — — % AEP Term Loan 150.0 5.17 % — — % AEP Term Loan 100.0 5.23 % — — % AEP Term Loan 125.0 4.87 % — — % Total Short-term Debt $ 4,112.2 $ 2,614.0 (a) Weighted-average rate as of December 31, 2022 and 2021, respectively. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2022 and 2021 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits are described in the following tables: Year Ended December 31, 2022: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2022 Limit (in millions) (as adjusted) AEP Texas $ 348.8 $ 652.3 $ 173.3 $ 247.8 $ (96.5) $ 500.0 AEPTCo 480.2 137.0 189.4 28.9 (195.5) 820.0 (a) APCo 438.4 214.2 181.7 45.4 (162.4) 500.0 I&M 318.6 23.0 105.2 22.3 (226.9) 500.0 OPCo 262.5 246.1 101.3 86.9 (172.9) 500.0 PSO 364.2 432.5 224.5 402.8 (364.2) 400.0 SWEPCo 358.4 156.6 219.3 109.7 (310.7) 400.0 Year Ended December 31, 2021: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2021 Limit (in millions) AEP Texas $ 355.5 $ 104.7 $ 172.5 $ 40.0 $ (26.9) $ 500.0 AEPTCo 444.9 117.3 189.1 29.7 (108.8) 820.0 (a) APCo 199.3 616.9 87.5 118.3 (178.5) 500.0 I&M 166.5 368.2 110.4 67.7 (71.8) 500.0 OPCo 259.2 622.9 61.6 127.2 42.0 500.0 PSO 267.7 747.3 134.0 113.1 (72.3) 400.0 SWEPCo 280.3 561.9 142.4 287.4 153.8 400.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above tables does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2022 and 2021 are included in Advances to Affiliates on each subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity is described in the following tables: Year Ended December 31, 2022: Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2022 (in millions) AEP Texas $ 7.0 $ 6.8 $ 6.9 SWEPCo 2.1 2.1 2.1 Year Ended December 31, 2021: Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2021 (in millions) AEP Texas $ 7.1 $ 6.9 $ 6.9 SWEPCo 2.1 2.1 2.1 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of December 31, 2022 and 2021 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limits are described in the following tables: Year Ended December 31, 2022: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2022 December 31, 2022 Borrowing Limit (in millions) $ 52.4 $ 141.8 $ 6.7 $ 57.5 $ 29.4 $ — $ 50.0 (a) Year Ended December 31, 2021: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2021 December 31, 2021 Borrowing Limit (in millions) $ 14.6 $ 224.2 $ 1.8 $ 118.0 $ 1.5 $ 12.7 $ 50.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table: Years Ended December 31, 2022 2021 2020 Maximum Interest Rate 5.28 % 0.48 % 2.70 % Minimum Interest Rate 0.10 % 0.02 % 0.27 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table: Average Interest Rate for Funds Borrowed Average Interest Rate for Funds Loaned Company 2022 2021 2020 2022 2021 2020 AEP Texas 1.08 % 0.33 % 1.51 % 1.99 % 0.26 % 0.81 % AEPTCo 1.81 % 0.32 % 1.29 % 2.47 % 0.10 % 1.99 % APCo 2.34 % 0.41 % 2.12 % 2.39 % 0.25 % 0.85 % I&M 2.57 % 0.33 % 1.07 % 2.20 % 0.23 % 1.18 % OPCo 3.51 % 0.27 % 0.99 % 1.22 % 0.14 % 2.06 % PSO 2.65 % 0.34 % 0.92 % 0.75 % 0.07 % 1.95 % SWEPCo 2.80 % 0.26 % 1.27 % 0.55 % 0.18 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table: Maximum Interest Rate Minimum Interest Rate Average Interest Rate Year Ended for Funds Loaned to for Funds Loaned to for Funds Loaned to December 31, Company the Nonutility Money Pool the Nonutility Money Pool the Nonutility Money Pool 2022 AEP Texas 5.28 % 0.46 % 2.23 % 2022 SWEPCo 5.28 % 0.46 % 2.23 % 2021 AEP Texas 0.58 % 0.21 % 0.37 % 2021 SWEPCo 0.58 % 0.21 % 0.37 % 2020 AEP Texas 2.70 % 0.27 % 1.18 % 2020 SWEPCo 2.70 % 0.27 % 1.18 % 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 for Funds for Funds for Funds for Funds for Funds for Funds Year Ended Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to December 31, AEP AEP AEP AEP AEP AEP 2022 5.28 % 0.46 % 5.28 % 0.46 % 2.08 % 2.07 % 2021 0.86 % 0.25 % 0.86 % 0.25 % 0.38 % 0.35 % 2020 2.70 % 0.27 % 2.70 % 0.27 % 1.20 % 1.13 % Interest expense related to short-term borrowing activities with the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 0.9 $ 0.3 $ 0.8 AEPTCo 3.5 0.6 1.5 APCo 5.6 0.1 2.8 I&M 2.9 0.2 1.4 OPCo 2.3 0.1 1.8 PSO 5.5 0.3 0.6 SWEPCo 4.9 0.3 1.5 Interest income related to short-term lending activities with the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 2.6 $ 0.1 $ 0.7 AEPTCo 1.6 0.4 2.4 APCo 2.8 0.3 0.7 I&M 0.5 0.2 0.2 OPCo 0.4 0.1 — PSO 0.3 — 0.1 SWEPCo 0.2 0.1 — Credit Facilities See “Letters of Credit” section of Note 6 for additional information. Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility was renewed in September 2022 and amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of December 31, 2022, the affiliated utility subsidiaries, with the exception of SWEPCo, were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. In response, in January 2023, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to their aged receivables requirements to bring SWEPCo back into compliance. Accounts receivable information for AEP Credit was as follows: Years Ended December 31, 2022 2021 2020 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.84 % 0.19 % 0.85 % Net Uncollectible Accounts Receivable Written Off $ 29.5 $ 26.5 $ 15.3 December 31, 2022 2021 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,167.7 $ 995.2 Short-term – Securitized Debt of Receivables 750.0 750.0 Delinquent Securitized Accounts Receivable 44.2 57.9 Bad Debt Reserves Related to Securitization 39.7 42.8 Unbilled Receivables Related to Securitization 360.9 307.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEP Texas and AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. KPCo ceased selling accounts receivable to AEP Credit in the first quarter of 2022, based on the expected sale to Liberty. As a result, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement were: December 31, Company 2022 2021 (in millions) APCo $ 194.4 $ 153.1 I&M 166.9 156.9 OPCo 478.6 392.7 PSO 155.5 114.5 SWEPCo 194.0 153.0 The fees paid to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2022 2021 (a) 2020 (in millions) APCo $ 9.4 $ 4.9 $ 5.2 I&M 9.7 7.0 7.9 OPCo 29.8 8.3 24.1 PSO 7.4 3.4 4.8 SWEPCo 9.4 5.4 6.7 (a) In 2021, due to the successful collection of accounts receivable balances during the COVID-19 pandemic, the allowance for doubtful accounts was reduced, resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid. The proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2022 2021 2020 (in millions) APCo $ 1,552.9 $ 1,324.1 $ 1,272.9 I&M 2,045.6 1,927.0 1,891.8 OPCo 3,101.3 2,458.5 2,366.2 PSO 1,809.5 1,406.4 1,221.0 SWEPCo 1,858.4 1,636.1 1,593.8

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
Stock-Based Compensation	Dec. 31, 2022
Stock-based Compensation	STOCK-BASED COMPENSATION The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries. Awards under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), which replaced prior long-term incentive plans effective April 2015, may be granted to employees and directors. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2022, 5,249,391 shares remained available for issuance under the 2015 LTIP. No new awards may be granted under the Prior Plan. Awards granted under the 2015 LTIP awards may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. Shares issued pursuant to a stock option or a stock appreciation right reduce the shares remaining available for grants under the 2015 LTIP by 0.286 of a share. Each share issued for any other award that settles in AEP stock reduces the shares remaining available for grants under the 2015 LTIP by one share. Cash settled awards do not reduce the number of shares remaining available under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. Performance Shares Performance units granted prior to 2017 were settled in cash rather than AEP common stock and did not reduce the number of shares remaining available under the 2015 LTIP. Those performance units had a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance shares granted in and after 2017 are settled in AEP common stock and reduce the aggregate share authorization. In all cases the number of performance shares held at the end of the three-year performance period is multiplied by the performance score for such period to determine the actual number of performance shares that participants realize. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee). Certain employees must satisfy a minimum stock ownership requirement. If those employees have not met their stock ownership requirement, a portion or all of their performance shares are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to a share of AEP common stock. AEP career shares are settled in AEP common stock after the participant’s termination of employment. AEP career shares are recorded in Paid-in Capital on the balance sheets. Amounts equivalent to cash dividends on both performance shares and AEP career shares accrue as additional shares. Management records compensation cost for performance shares over an approximately three-year vesting period. Performance shares are recorded as mezzanine equity on the balance sheets until the vesting date and compensation cost is calculated at fair value based on the performance metrics for each grant. Performance shares granted in 2022, 2021 and 2020 have three performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight, (b) total shareholder return with a 40% weight and (c) non-emitting generation capacity as a percentage of total owned and purchased capacity with a 10% weight. Performance shares granted in 2019 had two equally-weighted performance metrics: (a) three-year cumulative operating earnings per-share and (b) total shareholder return. The three-year cumulative operating earnings per-share and non-emitting generating capacity metrics are adjusted quarterly for changes in performance relative to the metric approved by the HR Committee. The total shareholder return metric is measured relative to a peer group of similar companies and is based on a third-party Monte Carlo valuation. The value related to this metric does not change over the three-year vesting period. The HR Committee awarded performance shares and reinvested dividends on outstanding performance shares and AEP career shares as follows: Years Ended December 31, Performance Shares 2022 2021 2020 Awarded Shares (in thousands) 530.3 565.0 424.8 Weighted-Average Share Fair Value at Grant Date $ 97.61 $ 81.02 $ 116.56 Vesting Period (in years) 3 3 3 Performance Shares and AEP Career Shares Years Ended December 31, 2022 2021 2020 Awarded Shares (in thousands) 63.3 74.5 73.4 Weighted-Average Fair Value at Grant Date $ 98.73 $ 84.48 $ 84.87 Vesting Period (in years) (a) (a) (a) (a) The vesting period for the reinvested dividends on performance shares is equal to the remaining life of the related performance shares. Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends. Performance scores and final awards are determined and approved by the HR Committee in accordance with the pre-established performance measures within approximately two months after the end of the performance period. The certified performance scores and shares earned for the three-year periods were as follows: Years Ended December 31, Performance Shares 2022 2021 2020 Certified Performance Score 131.1 % 102.9 % 128.2 % Performance Shares Earned 512,660 537,166 757,858 Performance Shares Mandatorily Deferred as AEP Career Shares 28,282 14,613 13,614 Performance Shares Voluntarily Deferred into the Incentive Compensation Deferral Program 23,609 22,915 26,936 Performance Shares to be Settled (a) 460,769 499,638 717,308 (a) Performance shares settled in AEP common stock in the quarter following the end of the year shown. The settlements were as follows: Years Ended December 31, Performance Shares and AEP Career Shares 2022 2021 2020 (in millions) AEP Common Stock Settlements for Performance Shares $ 43.2 $ 54.7 $ 75.4 AEP Common Stock Settlements for Career Share Distributions 5.1 4.0 1.9 A summary of the status of AEP’s nonvested Performance Shares as of December 31, 2022 and changes during the year ended December 31, 2022 were as follows: Nonvested Performance Shares Shares Weighted (in thousands) Nonvested as of January 1, 2022 923.8 $ 96.15 Awarded 530.3 97.61 Dividends 45.5 98.73 Vested (a) (395.8) 116.06 Forfeited (91.6) 84.81 Nonvested as of December 31, 2022 1,012.2 90.27 (a) The vested Performance Shares will be converted to 461 thousand shares based on the closing share price on the day before settlement. Monte Carlo Valuation AEP engages a third-party for a Monte Carlo valuation to calculate the fair value of the total shareholder return metric for the performance shares awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. The assumptions used in the Monte Carlo valuations were as follows: Years Ended December 31, Assumptions 2022 2021 2020 Valuation Period (in years) (a) 2.86 2.88 2.87 Expected Volatility Minimum 25.92 % 25.87 % 13.67 % Expected Volatility Maximum 40.82 % 39.90 % 28.15 % Expected Volatility Average 31.09 % 31.01 % 16.39 % Dividend Rate (b) — % — % — % Risk Free Rate 1.64 % 0.19 % 1.40 % (a) Period from award date to vesting date. (b) Equivalent to reinvesting dividends. Restricted Stock Units The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued AEP employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date, subject to the participant’s continued AEP employment, as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting, except the RSUs granted prior to 2017 to AEP’s executive officers which settled in cash. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. For RSUs that settle in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs that settled in cash, compensation cost was recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting was determined by multiplying the number of RSUs vested by the 20-day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date. The HR Committee awarded RSUs, including additional units awarded as dividends, as follows: Years Ended December 31, Restricted Stock Units 2022 2021 2020 Awarded Units (in thousands) 290.4 280.0 268.7 Weighted-Average Grant Date Fair Value $ 90.48 $ 80.39 $ 94.38 The total fair value and total intrinsic value of restricted stock units vested were as follows: Years Ended December 31, Restricted Stock Units 2022 2021 2020 (in millions) Fair Value of Restricted Stock Units Vested $ 17.8 $ 20.5 $ 22.9 Intrinsic Value of Restricted Stock Units Vested (a) 20.3 22.0 25.2 (a) Intrinsic value is calculated as market price at the vesting date. A summary of the status of AEP’s nonvested RSUs as of December 31, 2022 and changes during the year ended December 31, 2022 were as follows: Nonvested Restricted Stock Units Shares/Units Weighted (in thousands) Nonvested as of January 1, 2022 424.3 $ 84.86 Awarded 290.4 90.48 Vested (209.0) 85.15 Forfeited (46.1) 85.80 Nonvested as of December 31, 2022 459.6 88.05 The total aggregate intrinsic value of nonvested RSUs as of December 31, 2022 was $44 million and the weighted-average remaining contractual life was 1.8 years. Other Stock-Based Plans AEP also has a Stock Unit Accumulation Plan (SUAP) for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of the compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to non-employee directors are fully vested on their grant date. Stock units are paid to directors upon termination of their board service or up to 10 years later if the participant so elects. Cash settlements for stock units were calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. Effective June 30, 2022, the SUAP was amended to pay stock units in AEP common stock rather than cash. Management records compensation costs for stock units when the units are awarded and prior to June 2022 adjusted the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date. After five years of service on the Board of Directors, non-employee directors receive subsequent AEP stock units as contributions to an AEP stock fund under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. These balances are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash settlements for stock unit distributions were immaterial for the years ended December 31, 2022, 2021 and 2020. No stock units were settled in AEP common stock for the years ended December 31, 2022, 2021 and 2020. The Board of Directors awarded stock units, including units awarded for dividends, as follows: Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2022 2021 2020 Awarded Units (in thousands) 14.5 12.6 12.1 Weighted-Average Grant Date Fair Value $ 95.16 $ 84.54 $ 83.80 Share-based Compensation Plans For share-based payment arrangements the compensation cost, the actual tax benefit from the tax deductions for compensation cost recognized in income and the total compensation cost capitalized were as follows: Years Ended December 31, Share-based Compensation Plans 2022 2021 2020 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 63.3 $ 61.1 $ 53.8 Actual Tax Benefit 8.0 8.7 7.2 Total Compensation Cost Capitalized 16.0 16.9 20.4 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income. As of December 31, 2022, there was $78 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.41 years. Under the 2015 LTIP, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. AEP’s current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset tax withholding obligations.

Related Party Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2022
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation” section of Note 1 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 14. Power Coordination Agreement (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo) Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective Off-system Sales and purchase activities. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. System Integration Agreement (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The tables below represent revenues from affiliates, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries: Related Party Revenues AEP Texas AEPTCo APCo I&M (a) OPCo PSO SWEPCo (in millions) Year Ended December 31, 2022 Direct Sales to East Affiliates $ — $ — $ 169.7 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — — — 1.3 Transmission Revenues — 1,276.4 77.5 7.7 (3.6) — 51.5 Other Revenues 3.5 7.4 8.9 7.6 22.4 2.9 1.1 Total Affiliated Revenues $ 3.5 $ 1,283.8 $ 256.1 $ 15.3 $ 18.8 $ 2.9 $ 53.9 Related Party Revenues AEP Texas AEPTCo APCo I&M (a) OPCo PSO SWEPCo (in millions) Year Ended December 31, 2021 Direct Sales to East Affiliates $ — $ — $ 128.6 $ — $ — $ — $ — Transmission Revenues — 1,136.1 60.3 (2.5) (1.1) — 39.6 Other Revenues 3.9 17.8 9.0 6.3 25.9 4.2 1.4 Total Affiliated Revenues $ 3.9 $ 1,153.9 $ 197.9 $ 3.8 $ 24.8 $ 4.2 $ 41.0 Related Party Revenues AEP Texas AEPTCo APCo I&M (a) OPCo PSO SWEPCo (in millions) Year Ended December 31, 2020 Direct Sales to East Affiliates $ — $ — $ 112.5 $ — $ — $ — $ — Auction Sales to OPCo (b) — — 5.3 3.1 — — — Direct Sales to AEPEP 87.5 — — — — — — Transmission Revenues — 885.0 49.1 2.9 16.6 — 37.4 Other Revenues 3.3 11.3 7.8 4.5 24.9 5.2 1.6 Total Affiliated Revenues $ 90.8 $ 896.3 $ 174.7 $ 10.5 $ 41.5 $ 5.2 $ 39.0 (a) I&M’s affiliated revenues exclude capacity sales to KPCo from Rockport Plant, Unit 2 and barging, urea transloading and other transportation services to affiliates. See sections “Unit Power Agreements” and “I&M Barging, Urea Transloading and Other Services” below for additional information. (b) Refer to the Ohio Auctions section below for further information regarding these amounts. The tables below represent the purchased power expenses incurred for purchases from affiliates. AEP Texas, AEPTCo, APCo, PSO and SWEPCo did not purchase any or an immaterial amount of power from affiliates for the years ended December 31, 2022, 2021 and 2020. Related Party Purchases I&M OPCo (in millions) Year Ended December 31, 2022 Auction Purchases from AEPEP (a) $ — $ 9.8 Direct Purchases from AEGCo 241.8 — Total Affiliated Purchases $ 241.8 $ 9.8 Related Party Purchases I&M OPCo (in millions) Year Ended December 31, 2021 Auction Purchases from AEPEP (a) $ — $ 26.6 Auction Purchases from AEP Energy (a) — 25.3 Direct Purchases from AEGCo 217.9 — Total Affiliated Purchases $ 217.9 $ 51.9 Related Party Purchases I&M OPCo (in millions) Year Ended December 31, 2020 Auction Purchases from AEPEP (a) $ — $ 51.0 Auction Purchases from AEP Energy (a) — 58.7 Auction Purchases from AEPSC (a) — 10.0 Direct Purchases from AEGCo 172.8 — Total Affiliated Purchases $ 172.8 $ 119.7 (a) Refer to the Ohio Auctions section below for further information regarding this amount. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. PJM and SPP Transmission Service Charges (Applies to all Registrant Subsidiaries except AEP Texas) The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT. The following table shows the net transmission service charges recorded by APCo, I&M and OPCo: Years Ended December 31, Company 2022 2021 2020 (in millions) APCo $ 345.1 $ 302.0 $ 243.2 I&M 220.8 186.7 145.9 OPCo 608.2 508.9 417.4 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA in connection with the operation of the transmission assets of PSO and SWEPCo. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to PSO and SWEPCo through the SPP OATT. The following table shows the net transmission service charges recorded by PSO and SWEPCo: Years Ended December 31, Company 2022 2021 2020 (in millions) PSO $ 110.8 $ 94.7 $ 69.7 SWEPCo 62.1 56.2 31.3 The charges shown above are recorded in Other Operation expenses on the statements of income. AEPTCo provides transmission services to affiliates in accordance with the OATT, TA and TCA. AEPTCo recorded affiliated transmission revenues in Sales to AEP Affiliates on the statements of income. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. ERCOT Transmission Service Charges (Applies to AEP and AEP Texas) Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $28 million, $28 million and $28 million for transmission services for the years ended December 31, 2022, 2021 and 2020, respectively. The billings are recorded in Other Operation expenses on AEP Texas’ statements of income. Oklaunion PPA between AEP Texas and AEPEP (Applies to AEP Texas) In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agreed to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Power Station. The PPA was approved by the FERC. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP paid AEP Texas the full Property, Plant and Equipment balance through depreciation payments until termination of the PPA due to the plant closing in September 2020. See “Dispositions” section of Note 7 for additional information. AEP Texas recorded revenue of $88 million from AEPEP for the year ended December 31, 2020. This amount is included in Sales to AEP Affiliates on AEP Texas’ statements of income. Joint License Agreement (Applies to AEPTCo, APCo, I&M, OPCo and PSO) AEPTCo entered into a 50-year joint license agreement with APCo, I&M, KPCo, OPCo and PSO, respectively, allowing either party to occupy the granting party’s facilities or real property. In addition, AEPTCo entered into a 5-year joint license agreement with APCo and WPCo. After the expiration of these agreements, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. AEPTCo recorded the following costs in Other Operation expense related to these agreements: Years Ended December 31, Billing Company 2022 2021 2020 (in millions) APCo $ 2.5 $ 2.4 $ 0.9 I&M 6.1 4.8 3.0 KPCo 0.6 0.5 0.4 OPCo 5.2 4.6 4.5 PSO 0.1 0.4 0.4 WPCo 0.2 0.2 0.2 APCo, I&M, KPCo, OPCo, PSO and WPCo recorded income related to these agreements in Sales to AEP Affiliates on the statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. Unit Power Agreements (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all of its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028). In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term on December 7, 2022. Beginning December 8, 2022, AEGCo and I&M applied the joint plant accounting model to their respective 50% undivided interests in the jointly owned Rockport Plant, Unit 2 as well as any future investments made prior to the current estimated retirement date of December 2028. Prior to the termination of the Rockport Plant, Unit 2 lease, I&M assigned 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below for additional information. Beginning December 8, 2022, AEGCo billed 100% of its share of the Rockport Plant to I&M and ceased billing to KPCo. KPCo reached an agreement with I&M, from the end of the lease through May 2024, to buy capacity from Rockport Plant, Unit 2 through the PCA at a rate equal to PJM’s RPM clearing price. I&M’s capacity sales to KPCo were $199 thousand for the year ended December 31, 2022. UPA between AEGCo and KPCo On December 7, 2022, the UPA between AEGCo and KPCo ended upon the termination of the Rockport Plant, Unit 2 lease. Previously, pursuant to an assignment between I&M and KPCo and a UPA between AEGCo and KPCo, AEGCo sold KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo paid AEGCo in consideration for the right to receive such power, the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. As a result of the end of the UPA between AEGCo and KPCo, a prorated bill was recorded from AEGCo to KPCo to reflect costs incurred for the first seven days of December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading costs were $9 million, $11 million and $12 million for the years ended December 31, 2022, 2021 and 2020, respectively. I&M recorded the cost of transloading services in Fuel on the balance sheets. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance costs were as follows: Years Ended December 31, Company 2022 2021 2020 (in millions) I&M $ 0.6 $ 0.3 $ 0.9 PSO 0.6 0.4 0.7 SWEPCo 2.7 2.8 3.0 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2022 2021 2020 (in millions) AEGCo $ 11.3 $ 7.6 $ 10.6 APCo 36.1 40.1 43.7 KPCo 2.0 3.1 3.2 WPCo 4.7 3.2 3.3 Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value: Sales Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 3.0 $ 0.4 $ 0.9 AEPTCo 2.3 1.4 0.2 APCo 16.0 6.2 5.7 I&M 5.3 7.0 1.5 OPCo 7.6 9.2 7.0 PSO 2.5 0.5 1.1 SWEPCo 1.0 0.4 0.8 Purchases Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 1.3 $ 0.4 $ 1.5 AEPTCo 11.6 16.7 6.0 APCo 2.4 1.0 1.3 I&M 2.0 0.6 3.4 OPCo 2.0 1.4 1.2 PSO 7.6 0.3 0.4 SWEPCo 2.8 0.3 2.8 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. AEP Wind Holdings LLC PPAs (Applies to I&M, OPCo and SWEPCo) Prior to its acquisition, two of the 50% owned joint venture wind farms in the AEP Wind Holdings, LLC portfolio had existing PPAs with I&M, OPCo and SWEPCo. Fowler Ridge 2 has PPAs with I&M and OPCo for a portion of its energy production. The I&M portion totaled $12 million, $10 million and $11 million and the OPCo portion totaled $24 million, $20 million and $23 million respectively, for the years ended December 31, 2022, 2021 and 2020, respectively. The other joint venture wind farm, Flat Ridge 2, has a PPA with SWEPCo for a portion of its energy production which totaled $14 million, $14 million and $14 million of purchased electricity for the years ended December 31, 2022, 2021 and 2020, respectively. AEP disposed of its 50% interest in Flat Ridge 2 in the fourth quarter of 2022. See “Flat Ridge 2 Wind LLC” section of Note 7 for additional information. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital. Charitable Contributions to AEP Foundation The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. Charitable contributions to the AEP Foundation were recorded in Other Operation on the statements of income as follows: Year Ended Company December 31, 2022 (in millions) AEP $ 75.0 AEP Texas 9.9 AEPTCo 11.1 APCo 12.5 I&M 11.0 OPCo 8.1 PSO 5.8 SWEPCo 8.8 In 2021 and 2020, there were no charitable contributions made to the AEP Foundation. OKTCo Radial Assets Transfer (Applies to AEP, AEPTCo and PSO) In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo’s interests in its radial assets to PSO. OKTCo had previously constructed radial assets in the PSO service territory and after the radial assets were placed into service, management determined the radial assets were not eligible to be included as part of OKTCo’s SPP OATT formula rates. In October 2020, FERC approved the request and in December 2020, OKTCo completed the transfer of its interest in the radial assets to PSO, through Parent, at net book value. At the transfer date, the net book value of the radial assets were $60 million, before associated tax liabilities.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
Variable Interest Entities	Dec. 31, 2022
Variable Interest Entities	VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting. Consolidated Variable Interests Entities Sabine (Applies to AEP and SWEPCo) Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2022, 2021 and 2020 were $168 million , $162 million and $131 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation o f $155 million . Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work. This guarantee ends upon completion of reclamation. The mine end-of-life has been adjusted to March 2023, in order to align with the announced closure of the Pirkey Power Plant. Reclamation is expected to be complete by 2037 at an estimated cost of $135 million . Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation. SWEPCo recovers these costs through its fuel clauses. As of December 31, 2022, SWEPCo has recorded $122 million of mine reclamation costs in Asset Retirement Obligations and has collected $89 million through a rider for reclamation costs. The remaining $33 million is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. DCC Fuel (Applies to AEP and I&M) I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2022, 2021 and 2020 were $84 million , $91 million and $94 million, respectively. The leases were recorded as finance leases on I&M’s balance sheets as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The finance leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding (Applies to AEP and AEP Texas) Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas. Management has concluded that AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. As of December 31, 2022 and 2021, $70 million and $68 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $71 million and $141 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Transition Funding has securitized transition assets of $125 million and $184 million as of December 31, 2022 and 2021, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Restoration Funding (Applies to AEP and AEP Texas) Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas’ distribution system primarily due to damage caused by Hurricane Harvey. Management has concluded that AEP Texas is the primary beneficiary of Restoration Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. As of December 31, 2022 and 2021, $24 million and $23 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $150 million and $173 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Restoration Funding has securitized assets of $161 million and $183 million as of December 31, 2022 and 2021, respectively, which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Funding’s securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Restoration Funding’s assets and liabilities on the balance sheets. Appalachian Consumer Rate Relief Funding (Applies to AEP and APCo) Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. As of December 31, 2022 and 2021, $26 million and $26 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $147 million and $173 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $160 million and $185 million as of December 31, 2022 and 2021, respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit (Applies to AEP) AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 25% of AEP Credit’s short-term borrowing needs in excess of third-party financings. Any third-party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14. EIS (Applies to AEP) AEP’s subsidiaries participate in one protected cell of EIS for six lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third-parties access to this insurance. AEP’s subsidiaries and any allowed third-parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2022, 2021 and 2020 was $31 million , $30 million and $31 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy (Applies to AEP) Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. Transource Energy’s activities consist of the development, construction and operation of FERC-regulated transmission assets in Missouri, West Virginia, Pennsylvania, Maryland and Oklahoma. Transource Energy has a credit facility agreement where borrowings are loaned through intercompany lending agreements to its subsidiaries. The creditor to the agreement has no recourse to the general credit of AEP. Transource Energy’s credit facility agreement contains certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5% . See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. Apple Blossom Wind Holdings LLC and Black Oak Getty Wind Holdings LLC (Applies to AEP) AEP holds an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (collectively the Project Entities). The Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management concluded the Project Entities are VIEs and that AEP is the primary beneficiary of both based on its power as managing member to direct the respective activities that most significantly impact the Project Entities’ economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheets. The nonaffiliated interests in the Project Entities are presented in Noncontrolling Interests on the balance sheets. As of December 31, 2022 and 2021, AEP recognized $94 million and $108 million, respectively, of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets. The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the years ended December 31, 2022 and 2021, the HLBV method resulted in a loss of $9 million and $7 million, respectively, allocated to Noncontrolling Interests. Santa Rita East (Applies to AEP) AEP owns an 85% interest in Santa Rita East Wind Energy Holdings, LLC and its wholly-owned subsidiary, Santa Rita East Wind Energy, LLC (collectively, Santa Rita East). Santa Rita East is a partnership whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas. Santa Rita East delivers energy and provides renewable energy credits through three long-term PPAs totaling 260 MWs. The remaining 42 MWs of energy are sold at wholesale into ERCOT. Management has concluded that Santa Rita East is a VIE and that AEP is the primary beneficiary based on its power as managing member of the partnership to direct the activities that most significantly impact Santa Rita East’s economic performance. See the tables below for the classification of Santa Rita East’s assets and liabilities on the balance sheets. AEP recognized $24 million, $25 million and $23 million of PTCs attributable to Santa Rita East for the years ended December 31, 2022, 2021 and 2020, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Santa Rita East is presented in Noncontrolling Interests on the balance sheets. As of December 31, 2022 and 2021, AEP recorded $58 million and $59 million, respectively, of Noncontrolling Interests related to Santa Rita East in Equity on the balance sheets. Dry Lake (Applies to AEP) In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% ownership interest in the entity that owns Dry Lake Solar Project (collectively, Dry Lake). Dry Lake is a partnership whose sole purpose is to own, operate and maintain a 100 MW solar generation facility in southern Nevada. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Dry Lake delivers energy and provides renewable energy credits through a long-term PPA. Management has concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. See the table below for the classification of Dry Lake assets and liabilities on the balance sheets. The ITC attributable to Dry Lake for the years ended December 31, 2022 and 2021 which was recorded in Income Tax Expense (Benefit) on the statements of income was not material. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. As of December 31, 2022 and 2021, AEP recognized $34 million and $35 million of Noncontrolling Interest on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2022 Registrant Subsidiaries SWEPCo I&M AEP Texas Transition Funding AEP Texas Restoration Funding APCo (in millions) ASSETS Current Assets $ 108.3 $ 90.2 $ 27.0 $ 21.1 $ 13.5 Net Property, Plant and Equipment 7.2 179.1 — — — Other Noncurrent Assets 130.0 94.0 140.9 (a) 168.8 (b) 164.6 (c) Total Assets $ 245.5 $ 363.3 $ 167.9 $ 189.9 $ 178.1 LIABILITIES AND EQUITY Current Liabilities $ 25.4 $ 90.0 $ 73.2 $ 31.3 $ 29.3 Noncurrent Liabilities 219.4 273.3 90.4 157.4 146.9 Equity 0.7 — 4.3 1.2 1.9 Total Liabilities and Equity $ 245.5 $ 363.3 $ 167.9 $ 189.9 $ 178.1 (a) Includes an intercompany item eliminated in consolidation of $16 million . (b) Includes an intercompany item eliminated in consolidation of $7 million . (c) Includes an intercompany item eliminated in consolidation of $2 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2022 Other Consolidated VIEs AEP Credit Protected Transource Energy Apple Blossom and Black Oak Santa Rita East Dry Lake (in millions) ASSETS Current Assets $ 1,181.0 $ 194.5 $ 23.5 $ 8.3 $ 21.3 $ 4.0 Net Property, Plant and Equipment — — 482.3 216.5 421.6 142.6 Other Noncurrent Assets 9.0 0.3 2.7 13.6 0.1 0.3 Total Assets $ 1,190.0 $ 194.8 $ 508.5 $ 238.4 $ 443.0 $ 146.9 LIABILITIES AND EQUITY Current Liabilities $ 1,087.8 $ 46.4 $ 22.8 $ 4.5 $ 9.6 $ 1.0 Noncurrent Liabilities 0.9 79.1 218.6 5.4 7.3 0.7 Equity 101.3 69.3 267.1 228.5 426.1 145.2 Total Liabilities and Equity $ 1,190.0 $ 194.8 $ 508.5 $ 238.4 $ 443.0 $ 146.9 American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2021 Registrant Subsidiaries SWEPCo I&M AEP Texas Transition Funding AEP Texas Restoration Funding APCo (in millions) ASSETS Current Assets $ 77.2 $ 65.2 $ 24.9 $ 24.3 $ 16.0 Net Property, Plant and Equipment 51.8 118.6 — — — Other Noncurrent Assets 104.1 57.2 208.3 (a) 192.6 (b) 187.8 (c) Total Assets $ 233.1 $ 241.0 $ 233.2 $ 216.9 $ 203.8 LIABILITIES AND EQUITY Current Liabilities $ 18.9 $ 65.1 $ 71.2 $ 36.1 $ 29.0 Noncurrent Liabilities 214.3 175.9 157.8 179.6 172.9 Equity (0.1) — 4.2 1.2 1.9 Total Liabilities and Equity $ 233.1 $ 241.0 $ 233.2 $ 216.9 $ 203.8 (a) Includes an intercompany item eliminated in consolidation of $24 million. (b) Includes an intercompany item eliminated in consolidation of $8 million. (c) Includes an intercompany item eliminated in consolidation of $2 million. American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2021 Other Consolidated VIEs AEP Credit Protected Transource Energy Apple Blossom and Black Oak Santa Rita East Dry Lake (in millions) ASSETS Current Assets $ 996.6 $ 217.3 $ 38.8 $ 9.9 $ 7.6 $ 4.0 Net Property, Plant and Equipment — — 475.4 217.3 437.6 146.1 Other Noncurrent Assets 10.4 — 3.0 11.3 — 0.3 Total Assets $ 1,007.0 $ 217.3 $ 517.2 $ 238.5 $ 445.2 $ 150.4 LIABILITIES AND EQUITY Current Liabilities $ 953.1 $ 37.5 $ 12.5 $ 6.6 $ 5.8 $ 0.9 Noncurrent Liabilities 0.9 82.3 216.9 5.2 7.0 0.6 Equity 53.0 97.5 287.8 226.7 432.4 148.9 Total Liabilities and Equity $ 1,007.0 $ 217.3 $ 517.2 $ 238.5 $ 445.2 $ 150.4 Non-Consolidated Significant Variable Interests DHLC (Applies to AEP and SWEPCo) DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. The operations of DHLC are governed by the lignite mining agreement among SWEPCo, CLECO and DHLC. SWEPCo and CLECO share the executive board seats and voting rights equally. In accordance with the lignite mining agreement, each entity is responsible for 50% of DHLC’s obligations, including debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee earned by DHLC. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. SWEPCo’s total billings from DHLC for the years ended December 31, 2022 were not material, and for the years ended December 31, 2021 and 2020 were $47 million and $142 million, respectively. DHLC paid dividends of $25 million, $0 million, and $0 million to SWEPCo for the years ended December 31, 2022, 2021, and 2020, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2022 2021 As Reported on Maximum As Reported on Maximum (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 0.4 0.4 23.8 23.8 SWEPCo’s Share of Obligations — 36.8 — 50.3 Total Investment in DHLC $ 8.0 $ 44.8 $ 31.4 $ 81.7 OVEC (Applies to AEP and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2022, AEP’s ownership in OVEC was 43.47%. Parent owns 39.17% and OPCo owns 4.3%. APCo, I&M and OPCo are members to an intercompany power agreement. The Registrants’ power participation ratios are 15.69% for APCo, 7.85% for I&M and 19.93% for OPCo. Participants of this agreement are entitled to receive and are obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2022 and 2021, OVEC’s outstanding indebtedness was approximately $1.1 billion and $1.1 billion, respectively. Although they are not an obligor or guarantor, the Registrants’ are responsible for their respective ratio of OVEC’s outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 for additional information. AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and its subsidiary holds a significant variable interest in OVEC. Power to control decision making that significantly impacts the economic performance of OVEC is shared amongst the owners through their representation on the Board of Directors of OVEC and the representation of the sponsoring companies on the Operating Committee under the intercompany power agreement. AEP’s investment in OVEC was: December 31, 2022 2021 As Reported on Maximum As Reported on Maximum Exposure (in millions) Capital Contribution from AEP $ 4.4 $ 4.4 $ 4.4 $ 4.4 AEP’s Ratio of OVEC Debt (a) — 478.2 — 492.0 Total Investment in OVEC $ 4.4 $ 482.6 $ 4.4 $ 496.4 (a) Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $173 million, $86 million and $219 million as of December 31, 2022 and $177 million, $89 million and $226 million as of December 31, 2021, respectively. Power purchased by the Registrant Subsidiaries from OVEC is included in Purchased Electricity for Resale on the statements of income and is shown in the table below: Years Ended December 31, Company 2022 2021 2020 (in millions) APCo $ 119.3 $ 104.3 $ 94.4 I&M 59.7 52.2 47.2 OPCo 151.8 133.0 120.8 AEPSC (Applies to Registrant Subsidiaries) AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct-charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 236.8 $ 206.9 $ 199.4 AEPTCo 286.6 267.1 270.3 APCo 347.5 313.3 294.9 I&M 192.4 200.9 210.2 OPCo 272.5 234.9 232.8 PSO 142.3 123.7 113.2 SWEPCo 192.5 168.6 161.8 The carrying amount and classification of variable interest in AEPSC’s accounts payable were as follows: December 31, 2022 2021 Company As Reported on Maximum As Reported on Maximum (in millions) AEP Texas $ 27.8 $ 27.8 $ 22.2 $ 22.2 AEPTCo 31.6 31.6 23.3 23.3 APCo 41.5 41.5 44.1 44.1 I&M 27.7 27.7 21.8 21.8 OPCo 31.1 31.1 25.5 25.5 PSO 17.7 17.7 13.7 13.7 SWEPCo 23.8 23.8 20.5 20.5 AEGCo (Applies to I&M) AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Units 1 and 2. AEGCo sells all the output from the Rockport Plant to I&M. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2022, 2021 and 2020 wer e $242 million, $218 million and $173 million, respectively. The carrying amounts of I&M’s liabilities associated with AEGCo as of December 31, 2022 and 2021 were $17 million and $18 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. Significant Equity Method Investments in Unconsolidated Entities (Applies to AEP) For a discussion of the equity method of accounting, see the “Equity Investment in Unconsolidated Entities” section of Note 1. AEP Wind Holdings, LLC In September 2022, AEP signed a PSA with a nonaffiliate for AEP’s interest in Flat Ridge 2, one of the five joint ventures that were held as of December 31, 2021 by AEP. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements. As of December 31, 2022, through AEP Wind Holdings, LLC, AEP holds a 50% interest in four joint ventures in multiple states which own distinct generation facilities. BP Wind Energy holds the other 50% interest in each of these joint ventures. All four wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. The joint ventures are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the joint ventures and therefore applies the equity method of accounting. The following financial figures in the respective periods include the results Flat Ridge 2 prior to its disposal. As of December 31, 2022 and 2021, AEP’s carrying value of the investment in the joint ventures was $247 million and $399 million, respectively. As of December 31, 2022 and 2021, the difference between AEP’s carrying value and the amount of underlying equity in net assets was $62 million and $(3) million, respectively. The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. AEP’s equity earnings (loss) associated with the joint venture wind farms was $(194) million, $(12) million and $2 million for the years ended December 31, 2022, 2021, and 2020, respectively. AEP recognized $39 million, $33 million, and $36 million of PTCs attributable to the joint ventures for the years ended December 31, 2022, 2021, and 2020 respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income. See the “Impairments” section of Note 7 for additional information. ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50% membership interest in ETT and AEP Transmission Holdco holds a 50% membership interest in ETT. As a result, AEP, through

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
Property, Plant and Equipment	Dec. 31, 2022
Property, Plant and Equipment	18. PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the balance sheets. The following tables include the total plant balances as of December 31, 2022 and 2021: December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Regulated Property, Plant and Equipment Generation $ 23,759.7 (a) $ — $ — $ 6,776.8 $ 5,534.6 $ — $ 2,394.8 $ 5,476.2 (a) Transmission 33,221.7 6,301.5 12,335.4 4,482.8 1,842.2 3,198.6 1,164.4 2,479.8 Distribution 27,138.8 5,312.8 — 4,933.0 3,024.7 6,450.3 3,216.4 2,659.6 Other 5,528.9 1,020.4 476.6 849.2 796.1 1,040.6 466.0 582.6 CWIP 4,776.4 (a) 805.2 1,554.7 705.3 253.0 474.3 219.3 369.5 (a) Less: Accumulated Depreciation 23,118.0 1,759.5 1,027.1 5,397.3 4,117.8 2,564.3 1,839.4 3,314.8 Total Regulated Property, Plant and Equipment - Net 71,307.5 11,680.4 13,339.6 12,349.8 7,332.8 8,599.5 5,621.5 8,252.9 Nonregulated Property, Plant and Equipment - Net 2,031.6 1.2 0.3 29.4 78.7 9.8 5.0 9.3 Total Property, Plant and Equipment - Net $ 73,339.1 $ 11,681.6 $ 13,339.9 $ 12,379.2 $ 7,411.5 $ 8,609.3 $ 5,626.5 $ 8,262.2 December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Regulated Property, Plant and Equipment Generation $ 22,428.3 (a) $ — $ — $ 6,683.9 $ 5,531.8 $ — $ 1,802.4 $ 4,734.5 (a) Transmission 30,771.1 5,849.9 11,031.0 4,322.4 1,783.1 2,992.8 1,107.7 2,316.9 Distribution 25,457.4 4,917.2 — 4,683.3 2,800.1 6,070.6 3,004.9 2,514.3 Other 5,403.5 958.7 451.7 668.9 755.1 982.2 433.5 542.0 CWIP 3,734.8 (a) 551.3 1,402.2 469.9 302.8 365.0 156.0 240.7 (a) Less: Accumulated Depreciation 21,491.1 1,642.9 784.0 5,047.4 3,885.3 2,457.4 1,707.0 3,002.2 Total Regulated Property, Plant and Equipment - Net 66,304.0 10,634.2 12,100.9 11,781.0 7,287.6 7,953.2 4,797.5 7,346.2 Nonregulated Property, Plant and Equipment - Net 2,000.1 1.2 0.1 23.3 23.3 9.8 5.3 53.9 Total Property, Plant and Equipment - Net $ 68,304.1 $ 10,635.4 $ 12,101.0 $ 11,804.3 $ 7,310.9 $ 7,963.0 $ 4,802.8 $ 7,400.1 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 2.7% - 7.6% 20 - 132 2.7% - 7.8% 20 - 132 2.7% - 6.3% 20 - 132 Transmission 2.0% - 2.7% 24 - 75 2.0% - 2.6% 15 - 75 2.0% - 2.6% 15 - 75 Distribution 2.7% - 3.6% 7 - 78 2.8% - 3.6% 7 - 80 2.7% - 3.7% 7 - 78 Other 3.1% - 14.4% 5 - 75 3.0% - 12.5% 5 - 75 2.8% - 11.3% 5 - 75 AEP Texas 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Transmission 2.2% 50 - 75 2.2% 50 - 75 2.0% 50 - 75 Distribution 2.9% 7 - 70 2.9% 7 - 70 3.1% 7 - 70 Other 6.2% 5 - 50 5.8% 5 - 50 6.1% 5 - 50 AEPTCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Transmission 2.6% 24 - 75 2.5% 24 - 75 2.4% 24 - 75 Other 6.6% 5 - 56 6.7% 5 - 56 6.3% 5 - 64 APCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 3.6% 35 - 118 3.6% 35 - 118 3.3% 35 - 118 Transmission 2.2% 24 - 75 2.1% 15 - 75 2.2% 15 - 75 Distribution 3.6% 12 - 57 3.5% 12 - 57 3.7% 12 - 57 Other 7.3% 5 - 55 8.5% 5 - 55 7.8% 5 - 55 I&M 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 4.9% 20 - 132 4.7% 20 - 132 4.6% 20 - 132 Transmission 2.5% 44 - 67 2.4% 45 - 70 2.3% 45 - 70 Distribution 3.1% 14 - 71 3.4% 14 - 71 3.4% 14 - 71 Other 10.1% 5 - 45 9.0% 5 - 51 10.2% 5 - 51 OPCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.7% 11 - 70 2.9% 11 - 70 3.1% 14 - 65 Other 6.1% 5 - 50 6.1% 5 - 50 5.0% 5 - 50 PSO 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 3.1% 30 - 75 2.8% 30 - 75 3.1% 35 - 75 Transmission 2.5% 42 - 75 2.4% 42 - 75 2.2% 45 - 75 Distribution 2.9% 15 - 78 2.9% 15 - 78 2.9% 15 - 78 Other 6.8% 5 - 56 6.1% 5 - 56 5.7% 5 - 64 SWEPCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 2.7% 30 - 65 2.7% 30 - 65 2.7% 35 - 65 Transmission 2.3% 44 - 70 2.4% 49 - 74 2.3% 47 - 73 Distribution 2.9% 15 - 75 2.8% 15 - 80 2.7% 15 - 67 Other 9.0% 5 - 57 8.6% 5 - 58 8.5% 5 - 52 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo for 2022, 2021 and 2020. 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 3.8% - 8.7% 3 - 61 3.8% - 10.4% 10 - 59 3.6% - 4.0% 15 - 59 Transmission 2.8% 10 - 62 2.6% 30 - 40 2.5% 30 - 40 Distribution NA NA NA NA NA NA Other 25.2% 5 - 35 (a) 16.5% 5 - 35 (a) 16.1% 5 - 50 (a) In 2020 management announced plans to retire the Pirkey Plant in 2023 and the related depreciable lives have been adjusted accordingly. See Note 5 - Effects of Regulation for additional information. NA Not applicable. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (Applies to all Registrants except AEPTCo) The Registrants recorded the following revisions to ARO estimates as of December 31, 2022 and 2021: • As of December 31, 2022 and 2021, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $2 billion and $1.93 billion, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2022 and 2021, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $3.01 billion and $3.54 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheet s. In December 2021, I&M recorded a $58 million revision for Cook Plant as a result of the latest decommissioning cost study. The ARO liability was updated and changes from the previous study were driven primarily by general increases in the projected cost of labor and materials. • In 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. In June 2021, management completed fully designed and costed project plans for the Glen Lyn Station site and increased ash disposal ARO liabilities by an additional $79 million. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause. APCo is permitted to record carrying costs on the unrecovered balance of closure costs as a weighted-average cost of capital approved by the Virginia SCC. The legislation provides for regulatory recovery of these costs. • In September 2022, APCo recorded a $14 million revision due to an increase in estimated ash pond closure costs at the Amos Plant. • In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022. As a result, PSO and SWEPCo incurred additional ARO liabilities of $13 million and $15 million, respectively. See the “North Central Wind Energy Facilities” section of Note 7 for additional information. • In March 2022, SWEPCo recorded a $13 million revision due to an increase in estimated ash pond closure costs at the Pirkey Plant and the Welsh Plant. In June 2022, SWEPCo recorded a $16 million revision due to an increase in estimated reclamation costs at Sabine. In September 2022, SWEPCo recorded a $14 million revision due to an increase in estimated landfill closure costs at Pirkey Plant. In November 2022, SWEPCo recorded an additional $7 million revision related to an increase in estimated reclamation costs at Sabine. The following is a reconciliation of the 2022 and 2021 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2021 Accretion Liabilities Liabilities Revisions in ARO as of December 31, 2022 (in millions) AEP(b)(c)(d)(e)(f)(g) $ 2,741.7 $ 111.2 $ 37.4 $ (47.0) $ 100.3 $ 2,943.6 AEP Texas (b)(e) 4.4 0.3 — (0.2) — 4.5 APCo (b)(e) 404.6 15.8 3.0 (12.7) 17.0 427.7 I&M (b)(c)(e) 1,946.3 71.5 3.2 (0.6) 7.7 2,028.1 OPCo (e) 1.9 0.2 3.0 (0.1) — 5.0 PSO (b)(e)(g) 57.6 4.1 12.8 (0.7) 1.9 75.7 SWEPCo (b)(d)(e)(g) 222.7 11.9 15.4 (25.8) 56.7 280.9 Company ARO as of December 31, 2020 Accretion Liabilities Liabilities Revisions in ARO as of December 31, 2021 (in millions) AEP (b)(c)(d)(e)(f)(g) $ 2,516.7 $ 105.0 $ 22.8 $ (41.4) $ 138.6 $ 2,741.7 AEP Texas (b)(e) 4.6 0.2 — (0.4) — 4.4 APCo (b)(e) 313.1 13.7 — (6.9) 84.7 404.6 I&M (b)(c)(e) 1,813.8 72.9 0.3 (0.1) 59.4 1,946.3 OPCo (e) 1.9 0.1 — (0.1) — 1.9 PSO (b)(e)(g) 47.4 3.3 7.6 (0.7) — 57.6 SWEPCo (b)(d)(e)(g) 222.1 9.8 9.2 (20.9) 2.5 222.7 (a) Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs. (b) Includes ARO related to ash disposal facilities. (c) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $2 billion and $1.93 billion as of December 31, 2022 and 2021, respectively. (d) Includes ARO related to Sabine and DHLC. (e) Includes ARO related to asbestos removal. (f) Includes ARO related to solar farms. (g) Includes ARO related to wind farms. Allowance for Funds Used During Construction and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2022 2021 2020 (in millions) AEP $ 133.7 $ 139.7 $ 148.1 AEP Texas 19.7 21.5 19.4 AEPTCo 70.7 67.2 74.0 APCo 11.7 15.6 14.6 I&M 9.8 12.8 11.5 OPCo 13.9 10.8 12.5 PSO 1.5 2.4 4.0 SWEPCo 4.9 7.0 7.7 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2022 2021 2020 (in millions) AEP $ 63.0 $ 53.8 $ 66.0 AEP Texas 11.5 10.5 12.5 AEPTCo 22.4 21.0 25.5 APCo 6.5 7.5 7.9 I&M 5.7 5.1 5.7 OPCo 6.7 4.7 6.2 PSO 2.7 0.7 2.0 SWEPCo 4.3 3.0 3.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2022 Fuel Percent of Utility Plant Construction Accumulated (in millions) AEP Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 382.9 $ 16.4 $ 149.4 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 632.0 — 632.0 Turk Generating Plant (a) Coal 73.3 % 1,611.1 5.1 314.7 Total $ 2,626.0 $ 21.5 $ 1,096.1 I&M Rockport Generating Plant (b)(c)(d) Coal 50.0 % $ 1,357.4 $ 9.2 $ 905.1 PSO North Central Wind Energy Facilities (e)(f) Wind 45.5 % $ 889.3 $ 9.1 $ 28.1 SWEPCo Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 382.9 $ 16.4 $ 149.4 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 632.0 — 632.0 Turk Generating Plant (a) Coal 73.3 % 1,611.1 5.1 314.7 North Central Wind Energy Facilities (e)(f) Wind 54.5 % 1,066.8 10.1 35.2 Total $ 3,692.8 $ 31.6 $ 1,131.3 Registrant’s Share as of December 31, 2021 Fuel Percent of Utility Plant Construction Accumulated (in millions) AEP Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 377.6 $ 6.3 $ 133.5 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 613.8 — 528.3 Turk Generating Plant (a) Coal 73.3 % 1,598.0 10.2 285.6 Total $ 2,589.4 $ 16.5 $ 947.4 I&M Rockport Generating Plant (b)(c)(d) Coal 50.0 % $ 1,247.2 $ 13.9 $ 794.5 PSO North Central Wind Energy Facilities (e)(f) Wind 45.5 % $ 313.7 $ — $ 4.2 SWEPCo Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 377.6 $ 6.3 $ 133.5 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 613.8 — 528.3 Turk Generating Plant (a) Coal 73.3 % 1,598.0 10.2 285.6 North Central Wind Energy Facilities (e)(f) Wind 54.5 % 376.2 — 5.4 Total $ 2,965.6 $ 16.5 $ 952.8 (a) Operated by SWEPCo. (b) Operated by I&M. (c) Amounts include I&M's 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 was subject to a finance lease with a nonaffiliated company. In December 2022, the lease expired at which point I&M and AEGCo acquired 100% of the interests in Unit 2. See the "Rockport Plant Litigation" section of Note 6 for additional information. (d) AEGCo owns 50%. (e) PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Sundance was placed into service in April 2021. Maverick was placed into service in September 2021. Traverse was placed into service in March 2022. See the “Acquisitions” section of Note 7 for additional information. (f) Operated by PSO.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
Revenue from Contracts with Customers	Dec. 31, 2022
Revenue from Contracts with Customers	REVENUE FROM CONTRACTS WITH CUSTOMERS The disclosures in this note apply to all Registrants, unless indicated otherwise. Disaggregated Revenues from Contracts with Customers The table below represents AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue: Year Ended December 31, 2022 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 $ 4,498.6 $ 2,497.3 $ — $ — $ — $ — $ 6,995.9 Commercial Revenues 2,576.5 1,365.2 — — — — 3,941.7 Industrial Revenues (a) 2,543.8 711.3 — — — (0.9) 3,254.2 Other Retail Revenues 212.2 49.1 — — — — 261.3 Total Retail Revenues 9,831.1 4,622.9 — — — (0.9) 14,453.1 Wholesale and Competitive Retail Revenues: Generation Revenues 958.3 — — 271.2 — — 1,229.5 Transmission Revenues (b) 442.8 650.0 1,700.6 — — (1,413.2) 1,380.2 Renewable Generation Revenues (a) — — — 129.1 — (8.0) 121.1 Retail, Trading and Marketing Revenues (a) — — — 1,713.2 6.9 (10.1) 1,710.0 Total Wholesale and Competitive Retail Revenues 1,401.1 650.0 1,700.6 2,113.5 6.9 (1,431.3) 4,440.8 Other Revenues from Contracts with Customers (c) 241.1 247.3 8.2 12.1 93.9 (104.8) 497.8 Total Revenues from Contracts with Customers 11,473.3 5,520.2 1,708.8 2,125.6 100.8 (1,537.0) 19,391.7 Other Revenues: Alternative Revenue Programs (d) 3.8 (26.8) (31.8) — — (57.7) (112.5) Other Revenues (a) (e) 0.4 18.6 — 341.3 9.1 (9.1) 360.3 Total Other Revenues 4.2 (8.2) (31.8) 341.3 9.1 (66.8) 247.8 Total Revenues $ 11,477.5 $ 5,512.0 $ 1,677.0 $ 2,466.9 $ 109.9 $ (1,603.8) $ 19,639.5 (a) Amounts include affiliated and nonaffiliated revenues. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.3 billion. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $59 million. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Generation & Marketing includes economic hedge activity. Year Ended December 31, 2021 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 3,952.6 $ 2,138.2 $ — $ — $ — $ — $ 6,090.8 Commercial Revenues 2,208.5 1,081.2 — — — — 3,289.7 Industrial Revenues 2,168.2 395.2 — — — (0.8) 2,562.6 Other Retail Revenues 170.6 43.9 — — — — 214.5 Total Retail Revenues 8,499.9 3,658.5 — — — (0.8) 12,157.6 Wholesale and Competitive Retail Revenues: Generation Revenues 942.6 — — 137.9 — — 1,080.5 Transmission Revenues (a) 355.5 572.4 1,456.4 — — (1,206.0) 1,178.3 Renewable Generation Revenues (b) — — — 86.9 — (3.6) 83.3 Retail, Trading and Marketing Revenues (c) — — — 1,722.6 1.4 (51.6) 1,672.4 Total Wholesale and Competitive Retail Revenues 1,298.1 572.4 1,456.4 1,947.4 1.4 (1,261.2) 4,014.5 Other Revenues from Contracts with Customers (b) 187.5 194.2 17.1 7.2 60.1 (115.2) 350.9 Total Revenues from Contracts with Customers 9,985.5 4,425.1 1,473.5 1,954.6 61.5 (1,377.2) 16,523.0 Other Revenues: Alternative Revenue Programs (d) 13.5 48.8 52.7 — — (73.6) 41.4 Other Revenues (b) (e) (0.5) 19.0 — 209.1 10.7 (10.7) 227.6 Total Other Revenues 13.0 67.8 52.7 209.1 10.7 (84.3) 269.0 Total Revenues $ 9,998.5 $ 4,492.9 $ 1,526.2 $ 2,163.7 $ 72.2 $ (1,461.5) $ 16,792.0 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.1 billion. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $52 million. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Generation & Marketing includes economic hedge activity. Year Ended December 31, 2020 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 3,606.8 $ 2,086.9 $ — $ — $ — $ — $ 5,693.7 Commercial Revenues 2,016.2 1,048.6 — — — — 3,064.8 Industrial Revenues 2,018.0 390.1 — — — (0.7) 2,407.4 Other Retail Revenues 155.6 42.5 — — — — 198.1 Total Retail Revenues 7,796.6 3,568.1 — — — (0.7) 11,364.0 Wholesale and Competitive Retail Revenues: Generation Revenues 588.3 — — 131.9 — — 720.2 Transmission Revenues (a) 334.5 467.0 1,257.0 — — (1,006.7) 1,051.8 Renewable Generation Revenues (b) — — — 60.9 — (1.6) 59.3 Retail, Trading and Marketing Revenues (c) — — — 1,486.9 (5.5) (103.0) 1,378.4 Total Wholesale and Competitive Retail Revenues 922.8 467.0 1,257.0 1,679.7 (5.5) (1,111.3) 3,209.7 Other Revenues from Contracts with Customers (b) 163.2 157.8 22.4 2.3 92.5 (148.6) 289.6 Total Revenues from Contracts with Customers 8,882.6 4,192.9 1,279.4 1,682.0 87.0 (1,260.6) 14,863.3 Other Revenues: Alternative Revenue Programs (d) (3.2) 70.0 (80.6) — — 7.5 (6.3) Other Revenues (b) (e) — 83.0 — 43.6 9.8 (74.9) 61.5 Total Other Revenues (3.2) 153.0 (80.6) 43.6 9.8 (67.4) 55.2 Total Revenues $ 8,879.4 $ 4,345.9 $ 1,198.8 $ 1,725.6 $ 96.8 $ (1,328.0) $ 14,918.5 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $965 million. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $103 million. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Generation & Marketing includes economic hedge activity. The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries: Year Ended December 31, 2022 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 667.2 $ — $ 1,558.7 $ 852.4 $ 1,830.2 $ 816.3 $ 820.7 Commercial Revenues 417.5 — 643.4 550.2 947.7 489.2 612.3 Industrial Revenues (a) 139.6 — 664.0 602.9 571.7 372.5 393.5 Other Retail Revenues 35.3 — 87.1 5.0 13.9 102.9 10.1 Total Retail Revenues 1,259.6 — 2,953.2 2,010.5 3,363.5 1,780.9 1,836.6 Wholesale Revenues: Generation Revenues (b) — — 299.9 490.0 — 26.5 273.2 Transmission Revenues (c) 563.8 1,643.5 167.0 36.8 86.2 39.2 148.7 Total Wholesale Revenues 563.8 1,643.5 466.9 526.8 86.2 65.7 421.9 Other Revenues from Contracts with Customers (d) 24.6 8.2 100.6 122.4 222.4 29.1 24.7 Total Revenues from Contracts with Customers 1,848.0 1,651.7 3,520.7 2,659.7 3,672.1 1,875.7 2,283.2 Other Revenues: Alternative Revenue Programs (e) (1.2) (27.2) (1.3) 10.0 (25.6) (1.0) 1.2 Other Revenues (a) — — 0.5 (0.1) 18.6 — — Total Other Revenues (1.2) (27.2) (0.8) 9.9 (7.0) (1.0) 1.2 Total Revenues $ 1,846.8 $ 1,624.5 $ 3,519.9 $ 2,669.6 $ 3,665.1 $ 1,874.7 $ 2,284.4 (a) Amounts include affiliated and nonaffiliated revenues. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $170 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.3 billion, APCo was $78 million and SWEPCo was $51 million. The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $62 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Year Ended December 31, 2021 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 550.3 $ — $ 1,379.6 $ 805.4 $ 1,587.9 $ 651.9 $ 709.5 Commercial Revenues 358.5 — 556.3 507.2 722.7 378.9 529.3 Industrial Revenues 108.9 — 584.3 557.0 286.3 274.1 344.4 Other Retail Revenues 31.3 — 70.8 5.2 12.6 77.7 10.0 Total Retail Revenues 1,049.0 — 2,591.0 1,874.8 2,609.5 1,382.6 1,593.2 Wholesale Revenues: Generation Revenues (a) — — 302.7 318.1 — 22.9 386.6 Transmission Revenues (b) 497.5 1,393.9 128.8 33.7 74.9 37.5 122.7 Total Wholesale Revenues 497.5 1,393.9 431.5 351.8 74.9 60.4 509.3 Other Revenues from Contracts with Customers (c) 41.2 17.0 70.4 104.1 153.1 31.3 23.5 Total Revenues from Contracts with Customers 1,587.7 1,410.9 3,092.9 2,330.7 2,837.5 1,474.3 2,126.0 Other Revenues: Alternative Revenue Programs (d) 6.1 58.4 12.3 (4.0) 42.6 0.1 5.8 Other Revenues (e) — — — — 19.0 — — Total Other Revenues 6.1 58.4 12.3 (4.0) 61.6 0.1 5.8 Total Revenues $ 1,593.8 $ 1,469.3 $ 3,105.2 $ 2,326.7 $ 2,899.1 $ 1,474.4 $ 2,131.8 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.1 billion. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $60 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Amounts include affiliated and nonaffiliated revenues. Year Ended December 31, 2020 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 563.6 $ — $ 1,250.6 $ 794.1 $ 1,523.4 $ 579.4 $ 630.8 Commercial Revenues 366.7 — 517.0 499.3 682.0 320.1 466.7 Industrial Revenues 120.1 — 553.5 547.4 270.0 221.1 328.8 Other Retail Revenues 29.5 — 67.6 6.6 13.1 66.0 9.1 Total Retail Revenues 1,079.9 — 2,388.7 1,847.4 2,488.5 1,186.6 1,435.4 Wholesale Revenues: Generation Revenues (a) — — 230.2 274.6 — 15.1 162.0 Transmission Revenues (b) 399.9 1,210.3 130.8 29.0 67.0 27.5 111.2 Total Wholesale Revenues 399.9 1,210.3 361.0 303.6 67.0 42.6 273.2 Other Revenues from Contracts with Customers (c) 48.2 22.4 59.5 85.0 109.5 34.7 26.7 Total Revenues from Contracts with Customers 1,528.0 1,232.7 2,809.2 2,236.0 2,665.0 1,263.9 1,735.3 Other Revenues: Alternative Revenue Programs (d) 3.4 (87.0) (13.0) 5.8 66.6 2.2 3.2 Other Revenues (e) 87.5 — — — 17.5 — — Total Other Revenues 90.9 (87.0) (13.0) 5.8 84.1 2.2 3.2 Total Revenues $ 1,618.9 $ 1,145.7 $ 2,796.2 $ 2,241.8 $ 2,749.1 $ 1,266.1 $ 1,738.5 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $112 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $952 million. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $69 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) 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 REPs are due to AEP Texas within 35 days. Wholesale Revenues - Generation AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements. AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed. Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above. APCo has a performance obligation to supply wholesale electricity to KGPCo through a PPA. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above. Wholesale Revenues - Transmission AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM. AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT. The AEP East Companies are parties to the 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 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 transmission owner within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above. Marketing, Competitive Retail and Renewable Revenues AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation. Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly. Fixed Performance Obligations (Applies to AEP, APCo and I&M) The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of December 31, 2022. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues. Company 2023 2024-2025 2026-2027 After 2027 Total (in millions) AEP $ 85.5 $ 157.3 $ 133.9 $ 60.3 $ 437.0 APCo 16.1 32.2 23.2 11.7 83.2 I&M 4.6 9.2 9.2 4.5 27.5 Contract Assets and Liabilities Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of December 31, 2022 and 2021. When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of December 31, 2022 and 2021. Accounts Receivable from Contracts with Customers Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of December 31, 2022 and 2021. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information. The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets: Years Ended December 31, Company 2022 2021 (in millions) AEP Texas $ 0.1 $ 0.4 AEPTCo 113.8 95.5 APCo 64.5 117.8 I&M 75.3 61.2 OPCo 49.9 51.7 PSO 18.8 18.8 SWEPCo 19.1 24.7 Contract Costs Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of December 31, 2022 and 2021.

Goodwill

Goodwill	12 Months Ended
Goodwill	Dec. 31, 2022
Goodwill	GOODWILL The disclosure in this note applies to AEP only. AEP’s carrying amount of goodwill for the years ended December 31, 2022 and 2021 by operating segment are as follows: Corporate and Other Generation AEP Consolidated (in millions) Balance as of December 31, 2020 $ 37.1 $ 15.4 $ 52.5 Impairment Losses — — — Balance as of December 31, 2021 37.1 15.4 52.5 Impairment Losses — — — Balance as of December 31, 2022 $ 37.1 $ 15.4 $ 52.5 In the fourth quarters of 2022 and 2021, annual impairment tests were performed. The fair values of the reporting units with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. AEP does not have any accumulated impairment on existing goodwill.

Subsequent Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2022
Subsequent Events	SUBSEQUENT EVENTS Planned Disposition of the Competitive Contracted Renewables Portfolio (Generation & Marketing Segment) (Applies to AEP) In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. As of December 31, 2022, the competitive contracted renewable portfolio assets totaled 1.4 gigawatts of generation resources representing consolidated solar and wind assets, with a net book value of $1.2 billion, and a 50% interest in four joint venture wind farms, totaling $247 million, accounted for as equity method investments. In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the competitive contracted renewables portfolio and AEP signed an agreement to sell the competitive contracted renewables portfolio to a nonaffiliated party for $1.5 billion including the assumption of project debt. As part of the sale agreement, AEP provided the acquirer an indemnification related to certain losses, not to exceed $70 million, which could result from one of the joint venture wind farm’s inability to meet certain minimum performance requirements. The sale is subject to FERC approval, clearance from the Committee on Foreign Investment in the United States and approval under applicable competition laws. AEP expects to close on the sale in the second quarter of 2023 and receive cash proceeds, net of taxes, transaction fees and other customary closing adjustments, of approximately $1.2 billion. Management concluded the consolidated assets within the competitive contracted renewables portfolio met the accounting requirements to be presented as Held for Sale in the first quarter of 2023 based on the receipt of final bids, Board of Director approval to consummate a sale transaction and the signing of the sale agreement. AEP anticipates recording an estimated pretax loss ranging from $175 million to $225 million ($100 million to $150 million after-tax), in the first quarter of 2023 as a result of reaching Held for Sale status. Management concluded the impact of any other than temporary decline in the fair value of the four joint venture wind farms was not material to AEP’s December 31, 2022 financial statements. Any changes to the book value or carrying value of these assets, or the anticipated sale price, could further reduce future net income and impact financial condition.
Goodwill	GOODWILL The disclosure in this note applies to AEP only. AEP’s carrying amount of goodwill for the years ended December 31, 2022 and 2021 by operating segment are as follows: Corporate and Other Generation AEP Consolidated (in millions) Balance as of December 31, 2020 $ 37.1 $ 15.4 $ 52.5 Impairment Losses — — — Balance as of December 31, 2021 37.1 15.4 52.5 Impairment Losses — — — Balance as of December 31, 2022 $ 37.1 $ 15.4 $ 52.5 In the fourth quarters of 2022 and 2021, annual impairment tests were performed. The fair values of the reporting units with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. AEP does not have any accumulated impairment on existing goodwill.

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers continue to pay for certain legacy deferred generation-related costs through PUCO approved riders. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned subsidiaries and VIEs, of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries, Transition Funding (consolidated VIEs) and Restoration Funding (a consolidated VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash for Securitized Funding	Restricted Cash (Applies to AEP, AEP Texas and APCo) Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.
Other Temporary Investments	Other Temporary Investments (Applies to AEP) Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.
Inventory	InventoryFossil fuel inventories are carried at average cost with the exception of AGR, which carries these inventories at the lower of average cost or net realizable value. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the expected sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. For receivables related to KPCo and APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.
Concentrations of Credit Risk and Significant Customers	The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances and Renewable Energy Credits	Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo) In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost. For AEP’s competitive generation business, management records RECs at the lower of cost or net realizable value. The Registrants follow the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo) The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities
Deferred Fuel Costs	Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo) The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen, non-existent or not applicable to merchant operations, changes in fuel costs or sharing of Off-system Sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income. Retail and Wholesale Supply and Delivery of Electricity The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers. Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”. An estimated annual true-up is recorded by the Registrants in the fourth quarter of each calendar year and a final annual true-up is recognized by the Registrants in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. See Note 19 - Revenue from Contracts with Customers for additional information. Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo) The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. Unrealized MTM gains and losses are included on the balance sheets as Risk
Levelization of Nuclear Refueling Outage Costs	Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M) In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	AEP System Tax Allocation AEP and subsidiaries join in the filing of a consolidated federal income tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group. Income Taxes and Investment and Production Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the utility is able to utilize the ITC on a stand-alone basis. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.
Excise Taxes	Excise Taxes (Applies to all Registrants except AEPTCo) As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy	Goodwill (Applies to AEP)When the Registrants acquire a business, as defined by the accounting guidance for “Business Combinations,” management recognizes all acquired assets and liabilities at their fair value. To the extent that consideration exceeds the net fair value of the identified assets and liabilities, goodwill is recognized on the balance sheets. Goodwill is not amortized. Management tests acquired goodwill at the reporting unit level for impairment at least annually at its estimated fair value. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods.
Pension and Other Postretirement Plans	Pension and OPEB Plans (Applies to all Registrants except AEPTCo) AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans. AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo) AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 30 % Fixed Income 54 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 59 % Fixed Income 40 % Cash and Cash Equivalents 1 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are generally as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2022 and 2021, the fair value of securities on loan as part of the program was $83 million and $137 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2022 and 2021. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (Applies to AEP and I&M) Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment manager that 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 debt securities in the trust funds as available-for-sale due to their long-term purpose. 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. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Comprehensive Income (Loss)	Comprehensive Income (Loss) (Applies to all Registrants except AEPTCo and OPCo) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2022, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. All performance units awarded prior to 2017 and restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vested to executive officers were settled in cash. During 2019, all of the remaining performance units and restricted stock units that settle in cash were settled. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance shares granted to employees under the 2015 LTIP and previous long-term incentive plans. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends. Performance shares awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units were payable in cash to directors after their service ends. Effective in June 2022, these stock units became payable in AEP common stock rather than cash. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2022, 2021 and 2020 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur. For the years ended December 31, 2022, 2021 and 2020, compensation costs are included in Net Income for the performance shares, career shares, restricted stock units and the non-employee director stock units. Compensation costs may also be capitalized. See Note 15 - Stock-based Compensation for additional information.
Equity Method Investments	Equity Method Investments in Unconsolidated Entities (Applies to AEP and SWEPCo) The equity method of accounting is used for equity investments where either AEP or SWEPCo exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings (Loss) of Unconsolidated Subsidiaries on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recognized when the investment has experienced a loss in value that is other-than-temporary in nature. AEP’s significant equity method investments include ETT, DHLC and four joint venture interests which own distinct wind generation faciliti es.
Earnings Per Share	Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.
Asset Retirement Obligation	Asset Retirement Obligations (Applies to all Registrants except AEPTCo) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities. I&M records ARO for the decommissioning of the Cook Plant. AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned, inflation, and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since

Benefit Plans (Policies)

Benefit Plans (Policies)	12 Months Ended
Benefit Plans (Policies)	Dec. 31, 2022
Pension and Other Postretirement Plans	Pension and OPEB Plans (Applies to all Registrants except AEPTCo) AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans. AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	12 Months Ended
Derivatives and Hedging (Policies)	Dec. 31, 2022
Derivatives and Hedging	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of certain 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 and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other 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. 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 line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo) 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. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Credit-Risk-Related Contingent Features Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	12 Months Ended
Fair Value Measurements (Policies)	Dec. 31, 2022
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly-traded securities issued by AEP.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
Income Taxes (Policies)	Dec. 31, 2022
Income Tax Policy	AEP System Tax Allocation AEP and subsidiaries join in the filing of a consolidated federal income tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group. Income Taxes and Investment and Production Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the utility is able to utilize the ITC on a stand-alone basis. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.

Leases (Policies)

Leases (Policies)	12 Months Ended
Leases (Policies)	Dec. 31, 2022
Lease Policy	Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.Operating lease rentals and finance lease amortization costs are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. The amortization costs related to the Rockport finance lease were charged to Depreciation and Amortization. Interest on finance lease liabilities is generally charged to Interest Expense. Lease costs associated with capital projects are included in Property, Plant and Equipment on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed.

Stock-Based Compensation (Polic

Stock-Based Compensation (Policies)	12 Months Ended
Stock-Based Compensation (Policies)	Dec. 31, 2022
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2022, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. All performance units awarded prior to 2017 and restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vested to executive officers were settled in cash. During 2019, all of the remaining performance units and restricted stock units that settle in cash were settled. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance shares granted to employees under the 2015 LTIP and previous long-term incentive plans. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends. Performance shares awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units were payable in cash to directors after their service ends. Effective in June 2022, these stock units became payable in AEP common stock rather than cash. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2022, 2021 and 2020 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur. For the years ended December 31, 2022, 2021 and 2020, compensation costs are included in Net Income for the performance shares, career shares, restricted stock units and the non-employee director stock units. Compensation costs may also be capitalized. See Note 15 - Stock-based Compensation for additional information.
Stock Based Compensation [Member]
Stock-based Compensation	Awards under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), which replaced prior long-term incentive plans effective April 2015, may be granted to employees and directors. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2022, 5,249,391 shares remained available for issuance under the 2015 LTIP. No new awards may be granted under the Prior Plan. Awards granted under the 2015 LTIP awards may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. Shares issued pursuant to a stock option or a stock appreciation right reduce the shares remaining available for grants under the 2015 LTIP by 0.286 of a share. Each share issued for any other award that settles in AEP stock reduces the shares remaining available for grants under the 2015 LTIP by one share. Cash settled awards do not reduce the number of shares remaining available under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans.Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.41 years.Under the 2015 LTIP, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. AEP’s current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset tax withholding obligations.
Performance Units [Member]
Stock-based Compensation	Performance units granted prior to 2017 were settled in cash rather than AEP common stock and did not reduce the number of shares remaining available under the 2015 LTIP. Those performance units had a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance shares granted in and after 2017 are settled in AEP common stock and reduce the aggregate share authorization. In all cases the number of performance shares held at the end of the three-year performance period is multiplied by the performance score for such period to determine the actual number of performance shares that participants realize. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee). Certain employees must satisfy a minimum stock ownership requirement. If those employees have not met their stock ownership requirement, a portion or all of their performance shares are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to a share of AEP common stock. AEP career shares are settled in AEP common stock after the participant’s termination of employment. AEP career shares are recorded in Paid-in Capital on the balance sheets. Amounts equivalent to cash dividends on both performance shares and AEP career shares accrue as additional shares. Management records compensation cost for performance shares over an approximately three-year vesting period. Performance shares are recorded as mezzanine equity on the balance sheets until the vesting date and compensation cost is calculated at fair value based on the performance metrics for each grant. Performance shares granted in 2022, 2021 and 2020 have three performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight, (b) total shareholder return with a 40% weight and (c) non-emitting generation capacity as a percentage of total owned and purchased capacity with a 10% weight. Performance shares granted in 2019 had two equally-weighted performance metrics: (a) three-year cumulative operating earnings per-share and (b) total shareholder return. The three-year cumulative operating earnings per-share and non-emitting generating capacity metrics are adjusted quarterly for changes in performance relative to the metric approved by the HR Committee. The total shareholder return metric is measured relative to a peer group of similar companies and is based on a third-party Monte Carlo valuation. The value related to this metric does not change over the three-year vesting period.
Restricted Shares and Restricted Stock Units [Member]
Stock-based Compensation	The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued AEP employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date, subject to the participant’s continued AEP employment, as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting, except the RSUs granted prior to 2017 to AEP’s executive officers which settled in cash. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. For RSUs that settle in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs that settled in cash, compensation cost was recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting was determined by multiplying the number of RSUs vested by the 20-day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Stock-based Compensation	AEP also has a Stock Unit Accumulation Plan (SUAP) for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of the compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to non-employee directors are fully vested on their grant date. Stock units are paid to directors upon termination of their board service or up to 10 years later if the participant so elects. Cash settlements for stock units were calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. Effective June 30, 2022, the SUAP was amended to pay stock units in AEP common stock rather than cash. Management records compensation costs for stock units when the units are awarded and prior to June 2022 adjusted the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date. After five years of service on the Board of Directors, non-employee directors receive subsequent AEP stock units as contributions to an AEP stock fund under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. These balances are paid in cash upon termination of board service or up to 10 years later if the participant so elects.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	12 Months Ended
Variable Interest Entities (Policies)	Dec. 31, 2022
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. AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting.

Property, Plant and Equipment (

Property, Plant and Equipment (Policies)	12 Months Ended
Property, Plant and Equipment (Policies)	Dec. 31, 2022
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense.For regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Reconciliation of Cash, Cash Equivalents and Restricted Cash	December 31, 2022 AEP AEP Texas APCo (in millions) Cash and Cash Equivalents $ 509.4 $ 0.1 $ 7.5 Restricted Cash 47.1 32.7 14.4 Total Cash, Cash Equivalents and Restricted Cash $ 556.5 $ 32.8 $ 21.9 December 31, 2021 AEP AEP Texas APCo (in millions) Cash and Cash Equivalents $ 403.4 $ 0.1 $ 2.5 Restricted Cash 48.0 30.4 17.6 Total Cash, Cash Equivalents and Restricted Cash $ 451.4 $ 30.5 $ 20.1
Significant Customers	Significant Customers of AEP Texas: Reliant Energy, Direct Energy and TXU Energy (a) 2022 2021 2020 Percentage of Total Revenues 45 % 43 % 46 % Percentage of Accounts Receivable – Customers 42 % 41 % 40 % (a) In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica. Significant Customers of AEPTCo: AEP Subsidiaries 2022 2021 2020 Percentage of Total Revenues 79 % 79 % 78 % Percentage of Total Accounts Receivable 72 % 81 % 78 %
Target Asset Allocations	Pension Plan Assets Target Equity 30 % Fixed Income 54 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 59 % Fixed Income 40 % Cash and Cash Equivalents 1 %
Basic and Diluted EPS Calculations	Years Ended December 31, 2022 2021 2020 (in millions, except per-share data) $/share $/share $/share Earnings Attributable to AEP Common Shareholders $ 2,307.2 $ 2,488.1 $ 2,200.1 Weighted-Average Number of Basic AEP Common Shares Outstanding 511.8 $ 4.51 500.5 $ 4.97 495.7 $ 4.44 Weighted-Average Dilutive Effect of Stock-Based Awards 1.7 (0.02) 1.3 (0.01) 1.5 (0.02) Weighted-Average Number of Diluted AEP Common Shares Outstanding 513.5 $ 4.49 501.8 $ 4.96 497.2 $ 4.42
Supplementary Information	2022 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 3,072.8 $ 363.5 $ 346.2 $ 576.1 $ 511.9 $ 293.1 $ 226.2 $ 319.3 Amortization of Certain Securitized Assets 93.3 93.3 — — — — — — Amortization of Regulatory Assets and Liabilities 36.7 (4.4) — (0.2) 15.3 1.2 3.9 5.5 Total Depreciation and Amortization $ 3,202.8 $ 452.4 $ 346.2 $ 575.9 $ 527.2 $ 294.3 $ 230.1 $ 324.8 2021 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 2,717.1 $ 327.2 $ 297.3 $ 547.0 $ 424.9 $ 301.1 $ 185.9 $ 292.9 Amortization of Certain Securitized Assets 64.2 64.2 — — — — — — Amortization of Regulatory Assets and Liabilities 44.4 (4.4) — (0.8) 21.1 2.2 10.7 2.1 Total Depreciation and Amortization $ 2,825.7 $ 387.0 $ 297.3 $ 546.2 $ 446.0 $ 303.3 $ 196.6 $ 295.0 2020 Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 2,487.5 $ 364.2 $ 249.0 $ 507.8 $ 393.3 $ 275.0 $ 171.9 $ 271.2 Amortization of Certain Securitized Assets 171.3 171.3 — — — — — — Amortization of Regulatory Assets and Liabilities 24.0 (5.7) — (0.3) 18.3 1.6 1.6 1.5 Total Depreciation and Amortization $ 2,682.8 $ 529.8 $ 249.0 $ 507.5 $ 411.6 $ 276.6 $ 173.5 $ 272.7 Years Ended December 31, Cash Flow Information 2022 2021 2020 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 1,286.3 $ 1,137.2 $ 1,029.1 Income Taxes 116.8 13.2 (49.1) Noncash Investing and Financing Activities: Acquisitions Under Finance Leases 31.8 287.6 44.2 Construction Expenditures Included in Current Liabilities as of December 31, 1,258.9 1,180.4 975.4 Construction Expenditures Included in Noncurrent Liabilities as of December 31, — — 5.5 Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, — — 33.4 Noncash Contribution of Assets to Cedar Creek Project — (9.3) — Noncontrolling Interest Assumed - Dry Lake Solar Project — 35.3 — Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31, — — 110.6

Comprehensive Income (Tables)

Comprehensive Income (Tables)	12 Months Ended
Comprehensive Income (Tables)	Dec. 31, 2022
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Cash Flow Hedges Pension and OPEB For the Year Ended December 31, 2022 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2021 $ 163.7 $ (21.3) $ 115.6 $ (73.2) $ 184.8 Change in Fair Value Recognized in AOCI, Net of Tax 477.3 18.4 (a) — (155.4) 340.3 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (b) 0.1 — — — 0.1 Purchased Electricity for Resale (b) (528.6) — — — (528.6) Interest Expense (b) — 4.0 — — 4.0 Amortization of Prior Service Cost (Credit) — — (21.8) — (21.8) Amortization of Actuarial (Gains) Losses — — 8.6 — 8.6 Reclassifications from AOCI, before Income Tax (Expense) Benefit (528.5) 4.0 (13.2) — (537.7) Income Tax (Expense) Benefit (111.0) 0.8 (2.8) — (113.0) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (417.5) 3.2 (10.4) — (424.7) Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI — — — (21.1) (21.1) Income Tax (Expense) Benefit — — — (4.4) (4.4) Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit — — — (16.7) (16.7) Net Current Period Other Comprehensive Income (Loss) 59.8 21.6 (10.4) (172.1) (101.1) Balance in AOCI as of December 31, 2022 $ 223.5 $ 0.3 $ 105.2 $ (245.3) $ 83.7 AEP Cash Flow Hedges Pension and OPEB For the Year Ended December 31, 2021 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 123.7 $ (100.7) $ (85.1) Change in Fair Value Recognized in AOCI, Net of Tax 488.2 21.1 (a) — 27.5 536.8 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (b) 0.7 — — — 0.7 Purchased Electricity for Resale (b) (334.8) — — — (334.8) Interest Expense (b) — 6.5 — — 6.5 Amortization of Prior Service Cost (Credit) — — (19.4) — (19.4) Amortization of Actuarial (Gains) Losses — — 9.1 — 9.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit (334.1) 6.5 (10.3) — (337.9) Income Tax (Expense) Benefit (70.2) 1.4 (2.2) — (71.0) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (263.9) 5.1 (8.1) — (266.9) Net Current Period Other Comprehensive Income (Loss) 224.3 26.2 (8.1) 27.5 269.9 Balance in AOCI as of December 31, 2021 $ 163.7 $ (21.3) $ 115.6 $ (73.2) $ 184.8 Cash Flow Hedges Pension and OPEB For the Year Ended December 31, 2020 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (103.5) $ (11.5) $ 130.7 $ (163.4) $ (147.7) Change in Fair Value Recognized in AOCI, Net of Tax (89.2) (39.9) (a) — 62.7 (66.4) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (b) (0.4) — — — (0.4) Purchased Electricity for Resale (b) 167.6 — — — 167.6 Interest Expense (b) — 4.9 — — 4.9 Amortization of Prior Service Cost (Credit) — — (19.2) — (19.2) Amortization of Actuarial (Gains) Losses — — 10.3 — 10.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 167.2 4.9 (8.9) — 163.2 Income Tax (Expense) Benefit 35.1 1.0 (1.9) — 34.2 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 132.1 3.9 (7.0) — 129.0 Net Current Period Other Comprehensive Income (Loss) 42.9 (36.0) (7.0) 62.7 62.6 Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 123.7 $ (100.7) $ (85.1) AEP Texas Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ (1.3) $ 5.3 $ (10.5) $ (6.5) Change in Fair Value Recognized in AOCI, Net of Tax — — (3.2) (3.2) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.3 — — 1.3 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) Benefit 1.3 0.1 — 1.4 Income Tax (Expense) Benefit 0.3 — — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.0 0.1 — 1.1 Net Current Period Other Comprehensive Income (Loss) 1.0 0.1 (3.2) (2.1) Balance in AOCI as of December 31, 2022 $ (0.3) $ 5.4 $ (13.7) $ (8.6) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (2.3) $ 5.1 $ (11.7) $ (8.9) Change in Fair Value Recognized in AOCI, Net of Tax 0.1 — 1.2 1.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — (0.1) — (0.1) Amortization of Actuarial (Gains) Losses — 0.3 — 0.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.2 0.2 — 1.4 Income Tax (Expense) Benefit 0.3 — — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.9 0.2 — 1.1 Net Current Period Other Comprehensive Income (Loss) 1.0 0.2 1.2 2.4 Balance in AOCI as of December 31, 2021 $ (1.3) $ 5.3 $ (10.5) $ (6.5) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (3.4) $ 4.9 $ (14.3) $ (12.8) Change in Fair Value Recognized in AOCI, Net of Tax 0.1 — 2.6 2.7 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.3 — — 1.3 Amortization of Prior Service Cost (Credit) — (0.1) — (0.1) Amortization of Actuarial (Gains) Losses — 0.3 — 0.3 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.3 0.2 — 1.5 Income Tax (Expense) Benefit 0.3 — — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.0 0.2 — 1.2 Net Current Period Other Comprehensive Income (Loss) 1.1 0.2 2.6 3.9 Balance in AOCI as of December 31, 2020 $ (2.3) $ 5.1 $ (11.7) $ (8.9) APCo Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ 7.5 $ 1.2 $ 15.7 $ 24.4 Change in Fair Value Recognized in AOCI, Net of Tax — — (24.1) (24.1) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.0) — — (1.0) Amortization of Prior Service Cost (Credit) — (5.4) — (5.4) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.0) (5.4) — (6.4) Income Tax (Expense) Benefit (0.2) (1.1) — (1.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.8) (4.3) — (5.1) Net Current Period Other Comprehensive Income (Loss) (0.8) (4.3) (24.1) (29.2) Balance in AOCI as of December 31, 2022 $ 6.7 $ (3.1) $ (8.4) $ (4.8) Pension and OPEB Amortization Changes in Cash Flow Hedges - of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 2.6 $ 7.2 Change in Fair Value Recognized in AOCI, Net of Tax 9.2 — 13.1 22.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.1) — — (1.1) Amortization of Prior Service Cost (Credit) — (5.3) — (5.3) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.1) (5.3) — (6.4) Income Tax (Expense) Benefit (0.2) (1.1) — (1.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.9) (4.2) — (5.1) Net Current Period Other Comprehensive Income (Loss) 8.3 (4.2) 13.1 17.2 Balance in AOCI as of December 31, 2021 $ 7.5 $ 1.2 $ 15.7 $ 24.4 Pension and OPEB Amortization Changes in Cash Flow Hedges - of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ 0.9 $ 9.2 $ (5.1) $ 5.0 Change in Fair Value Recognized in AOCI, Net of Tax (0.7) — 7.7 7.0 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.3) — — (1.3) Amortization of Prior Service Cost (Credit) — (5.3) — (5.3) Amortization of Actuarial (Gains) Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3) (4.8) — (6.1) Income Tax (Expense) Benefit (0.3) (1.0) — (1.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0) (3.8) — (4.8) Net Current Period Other Comprehensive Income (Loss) (1.7) (3.8) 7.7 2.2 Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 2.6 $ 7.2 I&M Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ (6.7) $ 4.7 $ 0.7 $ (1.3) Change in Fair Value Recognized in AOCI, Net of Tax — — (0.3) (0.3) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8) — (0.8) Amortization of Actuarial (Gains) Losses — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.0 (0.4) — 1.6 Income Tax (Expense) Benefit 0.4 (0.1) — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 (0.3) — 1.3 Net Current Period Other Comprehensive Income (Loss) 1.6 (0.3) (0.3) 1.0 Balance in AOCI as of December 31, 2022 $ (5.1) $ 4.4 $ 0.4 $ (0.3) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (8.3) $ 4.8 $ (3.5) $ (7.0) Change in Fair Value Recognized in AOCI, Net of Tax — — 4.2 4.2 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8) — (0.8) Amortization of Actuarial (Gains) Losses — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.0 (0.1) — 1.9 Income Tax (Expense) Benefit 0.4 — — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 (0.1) — 1.5 Net Current Period Other Comprehensive Income (Loss) 1.6 (0.1) 4.2 5.7 Balance in AOCI as of December 31, 2021 $ (6.7) $ 4.7 $ 0.7 $ (1.3) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (9.9) $ 4.9 $ (6.6) $ (11.6) Change in Fair Value Recognized in AOCI, Net of Tax — — 3.1 3.1 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — (0.8) — (0.8) Amortization of Actuarial (Gains) Losses — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2.0 (0.1) — 1.9 Income Tax (Expense) Benefit 0.4 — — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.6 (0.1) — 1.5 Net Current Period Other Comprehensive Income (Loss) 1.6 (0.1) 3.1 4.6 Balance in AOCI as of December 31, 2020 $ (8.3) $ 4.8 $ (3.5) $ (7.0) PSO Cash Flow Hedge – For the Year Ended December 31, 2022 Interest Rate (in millions) Balance in AOCI as of December 31, 2021 $ — Change in Fair Value Recognized in AOCI, Net of Tax 1.3 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) — Reclassifications from AOCI, before Income Tax (Expense) Benefit — Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit — Net Current Period Other Comprehensive Income (Loss) 1.3 Balance in AOCI as of December 31, 2022 $ 1.3 Cash Flow Hedge – For the Year Ended December 31, 2021 Interest Rate (in millions) Balance in AOCI as of December 31, 2020 $ 0.1 Change in Fair Value Recognized in AOCI, Net of Tax — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (0.1) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1) Income Tax (Expense) Benefit — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1) Net Current Period Other Comprehensive Income (Loss) (0.1) Balance in AOCI as of December 31, 2021 $ — Cash Flow Hedge – For the Year Ended December 31, 2020 Interest Rate (in millions) Balance in AOCI as of December 31, 2019 $ 1.1 Change in Fair Value Recognized in AOCI, Net of Tax — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (1.3) Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3) Income Tax (Expense) Benefit (0.3) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0) Net Current Period Other Comprehensive Income (Loss) (1.0) Balance in AOCI as of December 31, 2020 $ 0.1 SWEPCo Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2022 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2021 $ 1.2 $ (4.4) $ 9.9 $ 6.7 Change in Fair Value Recognized in AOCI, Net of Tax — — (9.2) (9.2) Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) (0.1) — — (0.1) Amortization of Prior Service Cost (Credit) — (2.0) — (2.0) Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1) (2.0) — (2.1) Income Tax (Expense) Benefit — (0.4) — (0.4) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1) (1.6) — (1.7) Net Current Period Other Comprehensive Income (Loss) (0.1) (1.6) (9.2) (10.9) Balance in AOCI as of December 31, 2022 $ 1.1 $ (6.0) $ 0.7 $ (4.2) Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2021 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2020 $ (0.3) $ (2.8) $ 5.0 $ 1.9 Change in Fair Value Recognized in AOCI, Net of Tax — — 4.9 4.9 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.9 — — 1.9 Amortization of Prior Service Cost (Credit) — (2.0) — (2.0) Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.9 (2.0) — (0.1) Income Tax (Expense) Benefit 0.4 (0.4) — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.5 (1.6) — (0.1) Net Current Period Other Comprehensive Income (Loss) 1.5 (1.6) 4.9 4.8 Balance in AOCI as of December 31, 2021 $ 1.2 $ (4.4) $ 9.9 $ 6.7 Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total (in millions) Balance in AOCI as of December 31, 2019 $ (1.8) $ (1.3) $ 1.8 $ (1.3) Change in Fair Value Recognized in AOCI, Net of Tax — — 3.2 3.2 Amount of (Gain) Loss Reclassified from AOCI Interest Expense (b) 1.9 — — 1.9 Amortization of Prior Service Cost (Credit) — (2.0) — (2.0) Amortization of Actuarial (Gains) Losses — 0.1 — 0.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.9 (1.9) — — Income Tax (Expense) Benefit 0.4 (0.4) — — Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.5 (1.5) — — Net Current Period Other Comprehensive Income (Loss) 1.5 (1.5) 3.2 3.2 Balance in AOCI as of December 31, 2020 $ (0.3) $ (2.8) $ 5.0 $ 1.9 (a) The change in fair value includes $(10) million, $(7) million and $6 million for the years ended December 31, 2022, 2021 and 2020, respectively, related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. (b) Amounts reclassified to the referenced line item on the statements of income.

Effects of Regulation (Tables)

Effects of Regulation (Tables)	12 Months Ended
Effects of Regulation (Tables)	Dec. 31, 2022
Regulated Generating Units to be Retired	Plant Net Book Value Accelerated Depreciation Regulatory Asset Cost of Removal Projected Current Authorized Annual (dollars in millions) Northeastern Plant, Unit 3 $ 136.3 $ 145.8 $ 20.2 (b) 2026 (c) $ 14.9 Pirkey Plant 35.1 179.5 39.8 2023 (d) 11.7 Welsh Plant, Units 1 and 3 416.8 85.6 58.3 (e) 2028 (f) 37.9 (a) Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period. (b) Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement. (c) Northeastern Plant, Unit 3 is currently being recovered through 2040. (d) Pirkey Plant is currently being recovered through 2032 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions. (e) Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
Regulatory Assets	AEP December 31, Remaining Recovery Period 2022 2021 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 625.7 $ 409.4 1 year Under-recovered Fuel Costs - does not earn a return 588.5 183.9 1 year Unrecovered Winter Storm Fuel Costs - earns a return (a) 95.8 62.7 1 year Total Current Regulatory Assets $ 1,310.0 $ 656.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Pirkey Plant Accelerated Depreciation $ 116.5 $ 87.0 Welsh Plant, Units 1 and 3 Accelerated Depreciation 85.6 45.9 Unrecovered Winter Storm Fuel Costs 84.6 367.5 Dolet Hills Power Station Fuel Costs - Louisiana 32.0 30.9 Dolet Hills Power Station Accelerated Depreciation (b) 9.7 72.3 Kentucky Deferred Purchased Power Expenses — 47.5 Plant Retirement Costs - Unrecovered Plant, Louisiana — 35.2 Other Regulatory Assets Pending Final Regulatory Approval 27.2 9.3 Total Regulatory Assets Currently Earning a Return 355.6 695.6 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 407.1 298.3 2020-2022 Virginia Triennial Under-Earnings 37.9 15.1 Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9 Other Regulatory Assets Pending Final Regulatory Approval 55.6 56.0 Total Regulatory Assets Currently Not Earning a Return 526.5 395.3 Total Regulatory Assets Pending Final Regulatory Approval 882.1 1,090.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (c) 689.9 715.4 24 years Long-term Under-recovered Fuel Costs - Oklahoma 252.7 — 2 years Long-term Under-recovered Fuel Costs - Virginia 223.3 — 2 years Unrecovered Winter Storm Fuel Costs (d) 148.6 679.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 110.6 110.2 20 years Pirkey Plant Accelerated Depreciation - Louisiana 63.0 — 10 years Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction 56.6 66.6 6 years Kentucky Deferred Purchased Power Expenses 53.0 — 5 years Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station, Louisiana 45.1 — 10 years Meter Replacement Costs 34.2 44.9 5 years Environmental Control Projects 33.9 36.2 18 years Cook Plant Uprate Project 25.3 27.7 11 years Ohio Distribution Decoupling 19.5 41.6 2 years Other Regulatory Assets Approved for Recovery 102.9 119.9 various Total Regulatory Assets Currently Earning a Return 1,858.6 1,841.8 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 975.4 689.3 12 years Plant Retirement Costs - Asset Retirement Obligation Costs 308.5 297.9 20 years Unamortized Loss on Reacquired Debt 104.1 111.6 26 years Cook Plant Nuclear Refueling Outage Levelization 81.2 32.0 3 years Fuel and Purchased Power Adjustment Rider 76.3 40.8 2 years Plant Retirement Costs - Unrecovered Plant, Texas 51.7 51.9 24 years Peak Demand Reduction/Energy Efficiency 41.7 40.8 4 years Unrealized Loss on Forward Commitments 40.1 100.8 10 years Ohio Enhanced Service Reliability Plan 33.3 9.5 2 years Postemployment Benefits 32.1 32.5 3 years 2017-2019 Virginia Triennial Under-Earnings 30.1 — 2 years Vegetation Management 25.8 29.3 3 years Smart Grid Costs 25.4 19.3 2 years PJM/SPP Annual Formula Rate True-up 21.8 18.0 2 years Plant Retirement Costs - Unrecovered Plant, Arkansas 21.1 — 5 years Virginia Transmission Rate Adjustment Clause 18.7 37.2 2 years Storm-Related Costs 11.9 25.4 2 years Texas Transmission Cost Recovery Factor 3.8 30.6 2 years Other Regulatory Assets Approved for Recovery 118.3 119.2 various Total Regulatory Assets Currently Not Earning a Return 2,021.3 1,686.1 Total Regulatory Assets Approved for Recovery 3,879.9 3,527.9 Total Noncurrent Regulatory Assets $ 4,762.0 $ 4,618.8 (a) In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information. (b) 2022 amount includes the FERC jurisdiction. 2021 amounts include Arkansas, Louisiana and FERC jurisdictions. (c) Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information. (d) In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information. AEP Texas December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Texas Mobile Generation Lease Payments $ 17.6 $ — Total Regulatory Assets Currently Earning a Return 17.6 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 26.7 22.4 Vegetation Management Program 5.2 5.2 Texas Retail Electric Provider Bad Debt Expense 4.1 4.1 Other Regulatory Assets Pending Final Regulatory Approval 13.4 9.5 Total Regulatory Assets Currently Not Earning a Return 49.4 41.2 Total Regulatory Assets Pending Final Regulatory Approval 67.0 41.2 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 16.1 22.7 4 years Advanced Metering System — 10.6 Other Regulatory Assets Approved for Recovery 1.4 2.1 various Total Regulatory Assets Currently Earning a Return 17.5 35.4 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 173.2 119.0 12 years Vegetation Management Program 12.1 17.4 3 years Peak Demand Reduction/Energy Efficiency 11.9 14.5 2 years Storm-Related Costs 8.5 12.8 2 years Texas Transmission Cost Recovery Factor 3.8 30.6 2 years Other Regulatory Assets Approved for Recovery 4.3 4.3 various Total Regulatory Assets Currently Not Earning a Return 213.8 198.6 Total Regulatory Assets Approved for Recovery 231.3 234.0 Total Noncurrent Regulatory Assets $ 298.3 $ 275.2 AEPTCo December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Noncurrent Regulatory Assets Regulatory assets approved for recovery: Regulatory Assets Currently Not Earning a Return PJM/SPP Annual Formula Rate True-up $ 7.2 $ 8.5 2 years Total Regulatory Assets Approved for Recovery 7.2 8.5 Total Noncurrent Regulatory Assets $ 7.2 $ 8.5 APCo December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 180.7 $ 127.2 1 year Under-recovered Fuel Costs - does not earn a return 292.4 74.1 1 year Total Current Regulatory Assets $ 473.1 $ 201.3 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return COVID-19 - Virginia $ 7.0 $ 6.8 Total Regulatory Assets Currently Earning a Return 7.0 6.8 Regulatory Assets Currently Not Earning a Return Storm-Related Costs - West Virginia 72.6 53.7 2020-2022 Virginia Triennial Under-Earnings 37.9 15.1 Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9 Other Regulatory Assets Pending Final Regulatory Approval 1.1 3.6 Total Regulatory Assets Currently Not Earning a Return 137.5 98.3 Total Regulatory Assets Pending Final Regulatory Approval 144.5 105.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Long-term Under-recovered Fuel Costs - Virginia 223.3 — 2 years Plant Retirement Costs - Unrecovered Plant 75.6 110.0 21 years Other Regulatory Assets Approved for Recovery 0.4 0.4 various Total Regulatory Assets Currently Earning a Return 299.3 110.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 303.1 293.1 15 years Pension and OPEB Funded Status 108.3 62.7 12 years Unamortized Loss on Reacquired Debt 74.4 78.2 23 years 2017-2019 Virginia Triennial Under-Earnings 30.1 — 2 years Virginia Transmission Rate Adjustment Clause 18.7 37.2 2 years Virginia Clean Economy Act 16.7 — 2 years Peak Demand Reduction/Energy Efficiency 15.8 17.8 4 years Postemployment Benefits 13.7 13.3 3 years Vegetation Management Program - West Virginia 13.7 11.9 2 years Environmental Compliance Costs 4.3 13.7 2 years Other Regulatory Assets Approved for Recovery 16.0 14.2 various Total Regulatory Assets Currently Not Earning a Return 614.8 542.1 Total Regulatory Assets Approved for Recovery 914.1 652.5 Total Noncurrent Regulatory Assets $ 1,058.6 $ 757.6 I&M December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Current Regulatory Assets Under-recovered Fuel Costs, Michigan - earns a return $ 9.0 $ 6.4 1 year Under-recovered Fuel Costs, Indiana - does not earn a return 38.1 — 1 year Total Current Regulatory Assets $ 47.1 $ 6.4 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 0.1 Total Regulatory Assets Currently Earning a Return 0.1 0.1 Regulatory Assets Currently Not Earning a Return Storm-Related Costs - Indiana 21.6 — Other Regulatory Assets Pending Final Regulatory Approval 2.0 3.6 Total Regulatory Assets Currently Not Earning a Return 23.6 3.6 Total Regulatory Assets Pending Final Regulatory Approval 23.7 3.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 147.0 170.8 6 years Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction 56.6 66.6 6 years Cook Plant Uprate Project 25.3 27.7 11 years Deferred Cook Plant Life Cycle Management Project Costs - Michigan, FERC 12.1 13.1 12 years Cook Plant Turbine - Indiana 9.0 9.7 16 years Cook Plant Study Costs 8.7 9.4 13 years Other Regulatory Assets Approved for Recovery 11.9 6.0 various Total Regulatory Assets Currently Earning a Return 270.6 303.3 Regulatory Assets Currently Not Earning a Return Cook Plant Nuclear Refueling Outage Levelization 81.2 32.0 3 years Pension and OPEB Funded Status 26.9 — 12 years Unamortized Loss on Reacquired Debt 12.9 14.2 26 years Peak Demand Energy Efficiency 10.3 2.8 2 years Postemployment Benefits 7.7 9.0 3 years Storm-Related Costs - Indiana 3.4 12.6 2 years PJM Costs and Off-system Sales Margin Sharing - Indiana — 15.1 Other Regulatory Assets Approved for Recovery 22.9 18.2 various Total Regulatory Assets Currently Not Earning a Return 165.3 103.9 Total Regulatory Assets Approved for Recovery 435.9 407.2 Total Noncurrent Regulatory Assets $ 459.6 $ 410.9 OPCo December 31, Remaining Regulatory Assets: 2022 2021 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - does not earn a return $ 3.8 $ — 1 year Total Current Regulatory Assets $ 3.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm-Related Costs $ 33.8 $ 3.8 Total Regulatory Assets Pending Final Regulatory Approval 33.8 3.8 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Ohio Distribution Decoupling 19.5 41.6 2 years Ohio Basic Transmission Cost Rider 14.3 5.2 2 years Ohio Economic Development Rider 1.1 10.1 2 years Total Regulatory Assets Currently Earning a Return 34.9 56.9 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 142.7 83.3 12 years Unrealized Loss on Forward Commitments 40.0 92.1 10 years Ohio Enhanced Service Reliability Plan 33.3 9.5 2 years Smart Grid Costs 25.4 19.3 2 years Postemployment Benefits 6.2 6.2 3 years PJM Load Service Entity Formula Rate True-up — 7.5 Other Regulatory Assets Approved for Recovery 11.0 14.4 various Total Regulatory Assets Currently Not Earning a Return 258.6 232.3 Total Regulatory Assets Approved for Recovery 293.5 289.2 Total Noncurrent Regulatory Assets $ 327.3 $ 293.0 PSO December 31, Remaining 2022 2021 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 178.7 $ 194.6 1 year Total Current Regulatory Assets $ 178.7 $ 194.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm-Related Costs $ 25.5 $ 13.9 Other Regulatory Assets Pending Final Regulatory Approval 0.1 0.3 Total Regulatory Assets Pending Final Regulatory Approval 25.6 14.2 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Long-term Under-recovered Fuel Costs - Oklahoma 252.7 — 2 years Plant Retirement Costs - Unrecovered Plant (a) 240.6 227.6 24 years Environmental Control Projects 23.9 25.2 18 years Meter Replacement Costs 18.1 22.2 5 years Storm-Related Costs 8.4 17.4 2 years Unrecovered Winter Storm Fuel Costs — 679.3 (b) Other Regulatory Assets Approved for Recovery 9.1 9.8 various Total Regulatory Assets Currently Earning a Return 552.8 981.5 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 55.2 22.9 12 years Other Regulatory Assets Approved for Recovery 20.1 18.8 various Total Regulatory Assets Currently Not Earning a Return 75.3 41.7 Total Regulatory Assets Approved for Recovery 628.1 1,023.2 Total Noncurrent Regulatory Assets $ 653.7 $ 1,037.4 (a) Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information. (b) In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information. SWEPCo December 31, Remaining 2022 2021 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return (a) $ 257.2 $ 81.2 1 year Unrecovered Winter Storm Fuel Costs - earns a return (b) 95.8 62.7 1 year Total Current Regulatory Assets $ 353.0 $ 143.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Pirkey Plant Accelerated Depreciation $ 116.5 $ 87.0 Welsh Plant, Units 1 and 3 Accelerated Depreciation 85.6 45.9 Unrecovered Winter Storm Fuel Costs (b) 84.6 367.5 Dolet Hills Power Station Fuel Costs - Louisiana 32.0 30.9 Dolet Hills Power Station Accelerated Depreciation (c) 9.7 72.3 Plant Retirement Costs - Unrecovered Plant, Louisiana — 35.2 Other Regulatory Assets Pending Final Regulatory Approval 2.5 2.4 Total Regulatory Assets Currently Earning a Return 330.9 641.2 Regulatory Assets Currently Not Earning a Return Storm-Related Costs - Louisiana 151.5 148.0 Asset Retirement Obligation - Louisiana 11.8 10.3 Other Regulatory Assets Pending Final Regulatory Approval 16.0 18.4 Total Regulatory Assets Currently Not Earning a Return 179.3 176.7 Total Regulatory Assets Pending Final Regulatory Approval 510.2 817.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Unrecovered Winter Storm Fuel Costs (b) 148.6 — 5 years Pirkey Plant Accelerated Depreciation - Louisiana 63.0 — 10 years Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station - Louisiana 45.1 — 10 years Plant Retirement Costs - Unrecovered Plant, Welsh Plant, Unit 2 - Louisiana 35.2 — 10 years Plant Retirement Costs - Unrecovered Plant, Arkansas 13.1 13.7 20 years Environmental Controls Projects 10.0 11.0 10 years Other Regulatory Assets Approved for Recovery 6.8 5.2 various Total Regulatory Assets Currently Earning a Return 321.8 29.9 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 96.2 73.8 12 years Plant Retirement Costs - Unrecovered Plant, Texas 51.7 51.9 24 years Plant Retirement Costs - Unrecovered Plant, Arkansas 21.1 — 5 years Dolet Hills Power Station Fuel Costs - Arkansas 8.9 13.0 4 years Other Regulatory Assets Approved for Recovery 32.5 18.8 various Total Regulatory Assets Currently Not Earning a Return 210.4 157.5 Total Regulatory Assets Approved for Recovery 532.2 187.4 Total Noncurrent Regulatory Assets $ 1,042.4 $ 1,005.3 (a) 2022 amount includes Arkansas and Texas jurisdictions. 2021 amount includes Arkansas, Louisiana and Texas jurisdictions. (b) In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information. (c) 2022 amount includes the FERC jurisdiction. 2021 amounts include Arkansas, Louisiana and FERC jurisdictions.
Regulatory Liabilities	AEP December 31, Remaining 2022 2021 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 1.4 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 1.5 Total Current Regulatory Liabilities $ 1.4 $ 1.5 Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 149.7 $ 262.2 Total Regulatory Liabilities Currently Paying a Return 149.7 262.2 Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 4.1 2.3 Total Regulatory Liabilities Currently Not Paying a Return 4.1 2.3 Total Regulatory Liabilities Pending Final Regulatory Determination 153.8 264.5 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 3,392.4 3,229.9 (b) Income Taxes, Net (a) 2,504.5 2,792.0 (c) Rockport Plant, Unit 2 Accelerated Depreciation for Leasehold Improvements 53.8 4.2 6 years Renewable Energy Surcharge - Michigan 23.2 14.9 2 years Other Regulatory Liabilities Approved for Payment 9.5 16.2 various Total Regulatory Liabilities Currently Paying a Return 5,983.4 6,057.2 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 1,318.5 1,939.7 (d) Deferred Investment Tax Credits 237.3 248.5 34 years OVEC Purchased Power 47.1 14.8 2 years Spent Nuclear Fuel 45.8 49.5 (d) Unrealized Gain on Forward Commitments 45.2 40.4 2 years 2017-2019 Virginia Triennial Revenue Provision 39.1 41.6 26 years PJM Costs and Off-system Sales Margin Sharing - Indiana 34.2 — 2 years PJM Transmission Enhancement Refund 34.1 45.5 3 years Over-recovered Fuel Costs - Ohio 32.2 15.2 10 years Transition and Restoration Charges - Texas 29.4 26.3 7 years Peak Demand Reduction/Energy Efficiency 28.6 28.6 2 years Other Regulatory Liabilities Approved for Payment 86.9 62.6 various Total Regulatory Liabilities Currently Not Paying a Return 1,978.4 2,512.7 Total Regulatory Liabilities Approved for Payment 7,961.8 8,569.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,115.6 $ 8,834.4 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $277 million and $468 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. (d) Relieved when plant is decommissioned. AEP Texas December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 13.0 $ 13.0 Total Regulatory Liabilities Currently Paying a Return 13.0 13.0 Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination 1.8 — Total Regulatory Liabilities Currently Not Paying a Return 1.8 — Total Regulatory Liabilities Pending Final Regulatory Determination 14.8 13.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 766.8 744.7 (b) Income Taxes, Net (a) 431.6 445.3 (c) Other Regulatory Liabilities Approved for Payment 4.3 4.8 various Total Regulatory Liabilities Currently Paying a Return 1,202.7 1,194.8 Regulatory Liabilities Currently Not Paying a Return Transition and Restoration Charges 29.4 26.3 7 years Other Regulatory Liabilities Approved for Payment 12.7 7.9 various Total Regulatory Liabilities Currently Not Paying a Return 42.1 34.2 Total Regulatory Liabilities Approved for Payment 1,244.8 1,229.0 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,259.6 $ 1,242.0 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. AEPTCo December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Noncurrent Regulatory Liabilities Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 8.7 $ 8.7 Total Regulatory Liabilities Pending Final Regulatory Determination 8.7 8.7 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 358.8 271.4 (b) Income Taxes, Net (a) 355.8 371.6 (c) Total Regulatory Liabilities Approved for Payment 714.6 643.0 Total Noncurrent Regulatory Liabilities $ 723.3 $ 651.7 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $16 million and $26 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. APCo December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 30.5 $ 4.5 Total Regulatory Liabilities Pending Final Regulatory Determination 30.5 4.5 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 713.5 703.3 (b) Income Taxes, Net (a) 291.3 432.9 (c) Deferred Investment Tax Credits 0.3 0.3 31 years Total Regulatory Liabilities Currently Paying a Return 1,005.1 1,136.5 Regulatory Liabilities Currently Not Paying a Return 2017-2019 Virginia Triennial Revenue Provision 39.1 41.6 26 years Unrealized Gain on Forward Commitments 34.5 28.2 2 years Over-recovered Deferred Wind Power Costs - Virginia 13.6 8.4 2 years PJM Transmission Enhancement Refund 9.8 13.0 3 years Other Regulatory Liabilities Approved for Payment 11.0 6.6 various Total Regulatory Liabilities Currently Not Paying a Return 108.0 97.8 Total Regulatory Liabilities Approved for Payment 1,113.1 1,234.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,143.6 $ 1,238.8 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Relieved as removal costs are incurred. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $19 million and $84 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. I&M December 31, Remaining Regulatory Liabilities: 2022 2021 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs, Indiana - does not pay a return $ — $ 1.5 Total Current Regulatory Liabilities $ — $ 1.5 Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) (b) $ (87.7) $ — Total Regulatory Liabilities Pending Final Regulatory Determination (87.7) — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 170.7 179.7 (c) Income Taxes, Net (a) 168.6 182.6 (d) Renewable Energy Surcharge - Michigan 23.2 14.9 2 years Other Regulatory Liabilities Approved for Payment 3.0 7.0 various Total Regulatory Liabilities Currently Paying a Return 365.5 384.2 Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 1,318.5 1,939.7 (e) Spent Nuclear Fuel 45.8 49.5 (e) PJM Costs and Off-system Sales Margin Sharing - Indiana 34.2 — 2 years Deferred Investment Tax Credits 17.4 22.4 28 years Pension OPEB Funded Status — 27.6 Environmental Cost Rider - Indiana — 10.6 Other Regulatory Liabilities Approved for Payment 8.5 13.9 various Total Regulatory Liabilities Currently Not Paying a Return 1,424.4 2,063.7 Total Regulatory Liabilities Approved for Payment 1,789.9 2,447.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,702.2 $ 2,447.9 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Represents an income tax related regulatory asset, which is presented within net regulatory liabilities on the balance sheet. (c) Relieved as removal costs are incurred. (d) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $42 million and $90 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. (e) Relieved when plant is decommissioned. OPCo December 31, Remaining 2022 2021 Regulatory Liabilities: (in millions) Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ 0.2 $ 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 466.5 467.6 (a) Income Taxes, Net (b) 451.9 480.6 (c) Total Regulatory Liabilities Currently Paying a Return 918.4 948.2 Regulatory Liabilities Currently Not Paying a Return OVEC Purchased Power 47.1 14.8 2 years Over-recovered Fuel Costs 32.2 15.2 10 years Peak Demand Reduction/Energy Efficiency 23.6 22.5 2 years PJM Transmission Enhancement Refund 14.7 19.6 3 years Other Regulatory Liabilities Approved for Payment 7.8 0.4 various Total Regulatory Liabilities Currently Not Paying a Return 125.4 72.5 Total Regulatory Liabilities Approved for Payment 1,043.8 1,020.7 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,044.0 $ 1,020.9 (a) Relieved as removal costs are incurred. (b) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (c) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $162 million and $191 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years. PSO December 31, Remaining 2022 2021 Regulatory Liabilities: (in millions) Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) $ 51.3 $ 56.2 Total Regulatory Liabilities Pending Final Regulatory Determination 51.3 56.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (a) 380.1 423.8 (b) Asset Removal Costs 316.3 300.2 (c) Total Regulatory Liabilities Currently Paying a Return 696.4 724.0 Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.2 50.8 22 years Other Regulatory Liabilities Approved for Payment 13.2 4.3 various Total Regulatory Liabilities Currently Not Paying a Return 61.4 55.1 Total Regulatory Liabilities Approved for Payment 757.8 779.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 809.1 $ 835.3 (a) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $21 million and $46 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 2 years. (c) Relieved as removal costs are incurred. SWEPCo December 31, Remaining 2022 2021 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return (a) $ 1.4 $ — Total Current Regulatory Liabilities $ 1.4 $ — Noncurrent Regulatory Liabilities and Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Paying a Return Income Taxes, Net (b) $ 7.0 $ — Total Regulatory Liabilities Pending Final Regulatory Determination 7.0 — Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 481.2 461.3 (c) Income Taxes, Net (b) 327.6 330.2 (d) Other Regulatory Liabilities Approved for Payment 2.2 2.4 various Total Regulatory Liabilities Currently Paying a Return 811.0 793.9 Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Approved for Payment 7.7 13.0 various Total Regulatory Liabilities Currently Not Paying a Return 7.7 13.0 Total Regulatory Liabilities Approved for Payment 818.7 806.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 825.7 $ 806.9 (a) 2022 amount includes Louisiana jurisdiction. (b) Predominately pays a return due to the inclusion of Excess ADIT in rate base. (c) Relieved as removal costs are incurred. (d) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $7 million and $7 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 1 year.

Commitments, Guarantees and C_2

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
Commitments, Guarantees and Contingencies (Tables)	Dec. 31, 2022
Contractual Commitments	Contractual Commitments - AEP Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 1,499.8 $ 1,711.8 $ 345.4 $ 252.0 $ 3,809.0 Energy and Capacity Purchase Contracts 167.8 377.7 349.1 570.5 1,465.1 Total $ 1,667.6 $ 2,089.5 $ 694.5 $ 822.5 $ 5,274.1 Contractual Commitments - APCo Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 840.9 $ 1,102.9 $ 263.2 $ 9.2 $ 2,216.2 Energy and Capacity Purchase Contracts 40.5 82.7 79.9 127.0 330.1 Total $ 881.4 $ 1,185.6 $ 343.1 $ 136.2 $ 2,546.3 Contractual Commitments - I&M Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 200.9 $ 235.2 $ 53.3 $ 222.4 $ 711.8 Energy and Capacity Purchase Contracts 140.9 290.0 273.8 276.8 981.5 Total $ 341.8 $ 525.2 $ 327.1 $ 499.2 $ 1,693.3 Contractual Commitments - OPCo Less Than 2-3 Years 4-5 Years After Total (in millions) Energy and Capacity Purchase Contracts $ 34.4 $ 66.5 $ 63.7 $ 169.8 $ 334.4 Contractual Commitments - PSO Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 35.8 $ 14.5 $ — $ — $ 50.3 Energy and Capacity Purchase Contracts 47.1 116.3 122.8 91.4 377.6 Total $ 82.9 $ 130.8 $ 122.8 $ 91.4 $ 427.9 Contractual Commitments - SWEPCo Less Than 2-3 Years 4-5 Years After Total (in millions) Fuel Purchase Contracts (a) $ 133.7 $ 84.7 $ — $ — $ 218.4 Energy and Capacity Purchase Contracts 10.1 31.6 13.2 — 54.9 Total $ 143.8 $ 116.3 $ 13.2 $ — $ 273.3 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 287.4 January 2023 to December 2023 AEP Texas 1.8 July 2023

Acquisitions, Assets and Liab_2

Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments (Tables)	12 Months Ended
	Dec. 31, 2022
Lease Rental Costs	Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 157.5 $ 18.4 $ 1.1 $ 17.9 $ 29.5 $ 16.9 $ 11.8 $ 15.3 Finance Lease Cost: Amortization of Right-of-Use Assets 205.5 6.8 — 7.9 78.7 4.9 3.2 10.8 Interest on Lease Liabilities 13.4 1.3 — 2.0 3.1 0.8 0.6 2.1 Total Lease Rental Costs (a) $ 376.4 $ 26.5 $ 1.1 $ 27.8 $ 111.3 $ 22.6 $ 15.6 $ 28.2 Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 275.3 $ 18.4 $ 1.7 $ 19.3 $ 90.2 $ 19.0 $ 8.7 $ 12.1 Finance Lease Cost: Amortization of Right-of-Use Assets 74.7 6.7 — 7.7 12.9 4.9 3.2 11.0 Interest on Lease Liabilities 14.4 1.4 — 2.4 3.0 0.8 0.6 2.5 Total Lease Rental Costs (a) $ 364.4 $ 26.5 $ 1.7 $ 29.4 $ 106.1 $ 24.7 $ 12.5 $ 25.6 Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 279.6 $ 17.4 $ 2.6 $ 19.1 $ 101.5 $ 17.1 $ 7.8 $ 9.4 Finance Lease Cost: Amortization of Right-of-Use Assets 61.9 6.3 — 7.4 6.5 4.7 3.5 10.9 Interest on Lease Liabilities 15.4 1.5 — 2.7 3.1 0.9 0.7 2.2 Total Lease Rental Costs (a) $ 356.9 $ 25.2 $ 2.6 $ 29.2 $ 111.1 $ 22.7 $ 12.0 $ 22.5 (a) Excludes variable and short-term lease costs, which were immaterial.
Lease cost NCWFs	PSO SWEPCo December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (in millions) Project Sundance $ 12.6 $ 12.6 $ 15.1 $ 15.1 Maverick 18.0 18.0 21.6 21.6 Traverse 39.8 — 47.7 — Total $ 70.4 $ 30.6 $ 84.4 $ 36.7

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
Benefit Plans (Tables)	Dec. 31, 2022
Health Care Trend Rates	December 31, Health Care Trend Rates 2022 2021 Initial 7.50 % 6.25 % Ultimate 4.50 % 4.50 % Year Ultimate Reached 2029 2029
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	AEP Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,187.0 $ 5,544.5 $ 1,041.3 $ 1,210.9 Service Cost 123.1 129.2 7.4 9.5 Interest Cost 148.2 137.2 29.2 30.5 Actuarial Gain (983.4) (173.9) (109.8) (120.1) Plan Amendments — — — (5.4) Benefit Payments (402.2) (450.0) (140.1) (126.0) Participant Contributions — — 44.1 41.3 Medicare Subsidy — — 0.5 0.6 Benefit Obligation as of December 31, $ 4,072.7 $ 5,187.0 $ 872.6 $ 1,041.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 5,352.9 $ 5,556.6 $ 2,044.3 $ 1,946.7 Actual Gain (Loss) on Plan Assets (833.7) 239.2 (403.6) 176.5 Company Contributions (a) 7.7 7.1 4.6 5.8 Participant Contributions — — 44.1 41.3 Benefit Payments (402.2) (450.0) (140.1) (126.0) Fair Value of Plan Assets as of December 31, $ 4,124.7 $ 5,352.9 $ 1,549.3 $ 2,044.3 Funded Status as of December 31, $ 52.0 $ 165.9 $ 676.7 $ 1,003.0 (a) No contributions were made to the qualified pension plan for the years ended December 31, 2022 and 2021, respectively. Contributions to the non-qualified pension plans were $8 million and $7 million for the years ended December 31, 2022 and 2021, respectively. AEP Texas Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 419.8 $ 453.2 $ 80.5 $ 96.3 Service Cost 11.1 11.8 0.5 0.7 Interest Cost 12.1 11.2 2.2 2.4 Actuarial Gain (67.8) (10.9) (7.1) (12.3) Plan Amendments — — — (0.5) Benefit Payments (41.1) (45.5) (10.9) (9.3) Participant Contributions — — 3.4 3.2 Benefit Obligation as of December 31, $ 334.1 $ 419.8 $ 68.6 $ 80.5 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 444.9 $ 474.0 $ 168.8 $ 162.3 Actual Gain (Loss) on Plan Assets (69.2) 16.0 (33.0) 12.5 Company Contributions 0.5 0.4 — 0.1 Participant Contributions — — 3.4 3.2 Benefit Payments (41.1) (45.5) (10.9) (9.3) Fair Value of Plan Assets as of December 31, $ 335.1 $ 444.9 $ 128.3 $ 168.8 Funded Status as of December 31, $ 1.0 $ 25.1 $ 59.7 $ 88.3 APCo Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 621.7 $ 670.8 $ 167.3 $ 198.2 Service Cost 11.4 11.9 0.8 1.0 Interest Cost 17.5 16.4 4.7 4.9 Actuarial Gain (123.1) (28.5) (16.2) (21.4) Plan Amendments — — — (0.9) Benefit Payments (41.8) (48.9) (23.0) (21.3) Participant Contributions — — 7.0 6.6 Medicare Subsidy — — 0.1 0.2 Benefit Obligation as of December 31, $ 485.7 $ 621.7 $ 140.7 $ 167.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 683.3 $ 701.3 $ 302.3 $ 293.0 Actual Gain (Loss) on Plan Assets (109.8) 30.9 (59.3) 21.9 Company Contributions — — 1.6 2.1 Participant Contributions — — 7.0 6.6 Benefit Payments (41.8) (48.9) (23.0) (21.3) Fair Value of Plan Assets as of December 31, $ 531.7 $ 683.3 $ 228.6 $ 302.3 Funded Status as of December 31, $ 46.0 $ 61.6 $ 87.9 $ 135.0 I&M Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 612.1 $ 653.3 $ 118.6 $ 141.4 Service Cost 16.2 17.5 0.9 1.3 Interest Cost 17.0 16.2 3.4 3.5 Actuarial Gain (138.0) (29.5) (8.7) (16.8) Plan Amendments — — — (0.7) Benefit Payments (40.5) (45.4) (18.3) (15.3) Participant Contributions — — 6.0 5.2 Benefit Obligation as of December 31, $ 466.8 $ 612.1 $ 101.9 $ 118.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 681.5 $ 698.1 $ 248.7 $ 238.2 Actual Gain (Loss) on Plan Assets (107.4) 28.8 (45.9) 20.6 Company Contributions 0.1 — — — Participant Contributions — — 6.0 5.2 Benefit Payments (40.5) (45.4) (18.3) (15.3) Fair Value of Plan Assets as of December 31, $ 533.7 $ 681.5 $ 190.5 $ 248.7 Funded Status as of December 31, $ 66.9 $ 69.4 $ 88.6 $ 130.1 OPCo Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 470.7 $ 510.3 $ 104.9 $ 126.4 Service Cost 11.2 11.4 0.6 0.8 Interest Cost 13.3 12.5 3.0 3.0 Actuarial Gain (97.9) (24.1) (8.9) (15.6) Plan Amendments — — — (0.6) Benefit Payments (33.7) (39.4) (15.5) (13.6) Participant Contributions — — 4.8 4.5 Benefit Obligation as of December 31, $ 363.6 $ 470.7 $ 88.9 $ 104.9 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 524.8 $ 543.1 $ 220.0 $ 213.0 Actual Gain (Loss) on Plan Assets (84.8) 21.1 (43.1) 16.1 Company Contributions 0.1 — — — Participant Contributions — — 4.8 4.5 Benefit Payments (33.7) (39.4) (15.5) (13.6) Fair Value of Plan Assets as of December 31, $ 406.4 $ 524.8 $ 166.2 $ 220.0 Funded Status as of December 31, $ 42.8 $ 54.1 $ 77.3 $ 115.1 PSO Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 252.6 $ 279.9 $ 54.4 $ 64.0 Service Cost 7.4 8.0 0.4 0.6 Interest Cost 7.0 6.7 1.5 1.6 Actuarial Gain (52.9) (17.2) (5.2) (6.8) Plan Amendments — — — (0.3) Benefit Payments (21.8) (24.8) (7.9) (7.0) Participant Contributions — — 2.5 2.3 Benefit Obligation as of December 31, $ 192.3 $ 252.6 $ 45.7 $ 54.4 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 286.2 $ 299.8 $ 114.0 $ 107.8 Actual Gain (Loss) on Plan Assets (46.0) 11.1 (23.2) 10.9 Company Contributions 0.1 0.1 — — Participant Contributions — — 2.5 2.3 Benefit Payments (21.8) (24.8) (7.9) (7.0) Fair Value of Plan Assets as of December 31, $ 218.5 $ 286.2 $ 85.4 $ 114.0 Funded Status as of December 31, $ 26.2 $ 33.6 $ 39.7 $ 59.6 SWEPCo Pension Plans OPEB 2022 2021 2022 2021 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 317.7 $ 334.5 $ 65.2 $ 77.1 Service Cost 10.6 11.2 0.6 0.8 Interest Cost 9.1 8.5 1.8 1.9 Actuarial Gain (57.9) (3.5) (6.6) (9.2) Plan Amendments — — — (0.4) Benefit Payments (28.8) (33.0) (8.8) (7.6) Participant Contributions — — 2.9 2.6 Benefit Obligation as of December 31, $ 250.7 $ 317.7 $ 55.1 $ 65.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 308.3 $ 326.9 $ 136.6 $ 129.9 Actual Gain (Loss) on Plan Assets (48.3) 14.3 (27.7) 11.7 Company Contributions 0.1 0.1 — — Participant Contributions — — 2.9 2.6 Benefit Payments (28.8) (33.0) (8.8) (7.6) Fair Value of Plan Assets as of December 31, $ 231.3 $ 308.3 $ 103.0 $ 136.6 Funded (Underfunded) Status as of December 31, $ (19.4) $ (9.4) $ 47.9 $ 71.4
Benefit Amounts Recognized on the Balance Sheets	Pension Plans OPEB December 31, AEP 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 113.4 $ 244.3 $ 699.5 $ 1,040.8 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3) (7.6) (2.5) (2.7) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (55.1) (70.8) (20.3) (35.1) Funded Status $ 52.0 $ 165.9 $ 676.7 $ 1,003.0 Pension Plans OPEB December 31, AEP Texas 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 3.7 $ 28.7 $ 59.7 $ 88.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.4) (0.3) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (2.3) (3.3) — — Funded Status $ 1.0 $ 25.1 $ 59.7 $ 88.3 Pension Plans OPEB December 31, APCo 2022 2021 2022 2021 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 46.6 $ 62.4 $ 106.3 $ 158.1 Other Current Liabilities – Accrued Short-term Benefit Liability — — (1.6) (1.8) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (0.6) (0.8) (16.8) (21.3) Funded Status $ 46.0 $ 61.6 $ 87.9 $ 135.0 Pension Plans OPEB December 31, I&M 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 68.5 $ 71.4 $ 88.6 $ 130.1 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1) (0.1) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.5) (1.9) — — Funded Status $ 66.9 $ 69.4 $ 88.6 $ 130.1 Pension Plans OPEB December 31, OPCo 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ 43.1 $ 54.8 $ 77.3 $ 115.1 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (0.3) (0.7) — — Funded Status $ 42.8 $ 54.1 $ 77.3 $ 115.1 Pension Plans OPEB December 31, PSO 2022 2021 2022 2021 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 27.6 $ 35.5 $ 39.7 $ 59.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1) (0.1) — — Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (1.3) (1.8) — — Funded Status $ 26.2 $ 33.6 $ 39.7 $ 59.6 Pension Plans OPEB December 31, SWEPCo 2022 2021 2022 2021 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 47.9 $ 71.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1) (0.1) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.3) (9.3) — — Funded (Underfunded) Status $ (19.4) $ (9.4) $ 47.9 $ 71.4
Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 935.6 $ 894.7 $ 300.0 $ (103.6) Prior Service Cost (Credit) 0.2 0.2 (90.5) (161.9) Recorded as Regulatory Assets $ 841.8 $ 878.0 $ 126.0 $ (195.1) Deferred Income Taxes 19.9 3.6 17.5 (14.7) Net of Tax AOCI 74.1 13.3 66.0 (55.7) AEP Texas Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 161.9 $ 144.7 $ 29.7 $ (5.2) Prior Service Credit — — (7.6) (13.7) Recorded as Regulatory Assets $ 151.2 $ 136.7 $ 22.0 $ (17.7) Deferred Income Taxes 2.4 1.8 0.1 (0.2) Net of Tax AOCI 8.3 6.2 — (1.0) APCo Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 95.6 $ 83.9 $ 40.5 $ (18.9) Prior Service Credit — — (13.4) (23.8) Recorded as Regulatory Assets $ 93.6 $ 82.5 $ 14.7 $ (19.8) Deferred Income Taxes 0.4 0.3 2.5 (4.9) Net of Tax AOCI 1.6 1.1 9.9 (18.0) I&M Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ (6.9) $ (1.6) $ 40.2 $ (10.7) Prior Service Credit — — (12.4) (22.1) Recorded as Regulatory Assets/Liabilities (a) $ 4.8 $ 3.1 $ 22.1 $ (30.7) Deferred Income Taxes (2.4) (1.0) 1.2 (0.4) Net of Tax AOCI (9.3) (3.7) 4.5 (1.7) (a) Recorded as a Regulatory Asset as of December 31, 2022 and recorded as a Regulatory Liability as of December 31, 2021. OPCo Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 124.3 $ 118.1 $ 27.6 $ (18.5) Prior Service Credit — — (9.2) (16.3) Recorded as Regulatory Assets $ 124.3 $ 118.1 $ 18.4 $ (34.8) PSO Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 38.8 $ 35.0 $ 22.0 $ (2.1) Prior Service Credit — — (5.6) (10.0) Recorded as Regulatory Assets $ 38.8 $ 35.0 $ 16.4 $ (12.1) SWEPCo Pension Plans OPEB December 31, 2022 2021 2022 2021 Components (in millions) Net Actuarial (Gain) Loss $ 77.6 $ 76.4 $ 25.0 $ (3.5) Prior Service Credit — — (7.0) (12.3) Recorded as Regulatory Assets $ 77.6 $ 76.4 $ 11.2 $ (8.9) Deferred Income Taxes — — 1.5 (1.4) Net of Tax AOCI — — 5.3 (5.5)
Components of Change in Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 103.9 $ (183.4) $ 403.6 $ (205.5) Amortization of Actuarial Loss (63.0) (101.5) — — Prior Service Credit — — — (5.5) Amortization of Prior Service Credit — — 71.4 70.9 Change for the Year Ended December 31, $ 40.9 $ (284.9) $ 475.0 $ (140.1) AEP Texas Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 22.4 $ (7.5) $ 34.9 $ (17.5) Amortization of Actuarial Loss (5.2) (8.3) — — Prior Service Credit — — — (0.4) Amortization of Prior Service Credit — — 6.1 6.0 Change for the Year Ended December 31, $ 17.2 $ (15.8) $ 41.0 $ (11.9) APCo Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 19.1 $ (30.4) $ 59.4 $ (30.0) Amortization of Actuarial Loss (7.4) (12.0) — — Prior Service Credit — — — (0.9) Amortization of Prior Service Credit — — 10.4 10.3 Change for the Year Ended December 31, $ 11.7 $ (42.4) $ 69.8 $ (20.6) I&M Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.8 $ (29.4) $ 50.9 $ (26.3) Amortization of Actuarial Loss (7.1) (11.7) — — Prior Service Credit — — — (0.7) Amortization of Prior Service Credit — — 9.7 9.6 Change for the Year Ended December 31, $ (5.3) $ (41.1) $ 60.6 $ (17.4) OPCo Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.7 $ (22.8) $ 46.1 $ (22.1) Amortization of Actuarial Loss (5.5) (9.1) — — Prior Service Credit — — — (0.6) Amortization of Prior Service Credit — — 7.1 7.2 Change for the Year Ended December 31, $ 6.2 $ (31.9) $ 53.2 $ (15.5) PSO Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.7 $ (16.0) $ 24.1 $ (12.6) Amortization of Actuarial Loss (2.9) (4.9) — — Prior Service Credit — — — (0.3) Amortization of Prior Service Credit — — 4.4 4.4 Change for the Year Ended December 31, $ 3.8 $ (20.9) $ 28.5 $ (8.5) SWEPCo Pension Plans OPEB 2022 2021 2022 2021 Components (in millions) Actuarial (Gain) Loss During the Year $ 5.0 $ (4.3) $ 28.5 $ (15.0) Amortization of Actuarial Loss (3.8) (6.2) — — Prior Service Credit — — — (0.4) Amortization of Prior Service Credit — — 5.3 5.3 Change for the Year Ended December 31, $ 1.2 $ (10.5) $ 33.8 $ (10.1)
Allocated Assets of Investments	Pension Plan OPEB December 31, Company 2022 2021 2022 2021 AEP Texas 8.1 % 8.3 % 8.3 % 8.3 % APCo 12.9 % 12.8 % 14.8 % 14.8 % I&M 12.9 % 12.7 % 12.3 % 12.2 % OPCo 9.9 % 9.8 % 10.7 % 10.8 % PSO 5.3 % 5.3 % 5.5 % 5.6 % SWEPCo 5.6 % 5.8 % 6.6 % 6.7 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 3,827.4 $ 315.4 $ 470.1 $ 443.8 $ 344.1 $ 179.1 $ 234.0 Nonqualified Pension Plans 55.6 2.5 0.3 1.2 0.1 1.2 1.1 Total as of December 31, 2022 $ 3,883.0 $ 317.9 $ 470.4 $ 445.0 $ 344.2 $ 180.3 $ 235.1 Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,822.5 $ 391.4 $ 597.0 $ 575.2 $ 440.0 $ 232.1 $ 291.4 Nonqualified Pension Plans 69.7 3.3 0.4 1.2 0.3 1.5 1.3 Total as of December 31, 2021 $ 4,892.2 $ 394.7 $ 597.4 $ 576.4 $ 440.3 $ 233.6 $ 292.7
Underfunded Projected Benefit Obligation	AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 61.5 $ 2.7 $ 0.6 $ 1.6 $ 0.3 $ 1.5 $ 250.7 Fair Value of Plan Assets — — — — — — 231.3 Underfunded Projected Benefit Obligation as of December 31, 2022 $ (61.5) $ (2.7) $ (0.6) $ (1.6) $ (0.3) $ (1.5) $ (19.4) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 78.4 $ 3.6 $ 0.8 $ 1.9 $ 0.7 $ 1.9 $ 317.7 Fair Value of Plan Assets — — — — — — 308.3 Underfunded Projected Benefit Obligation as of December 31, 2021 $ (78.4) $ (3.6) $ (0.8) $ (1.9) $ (0.7) $ (1.9) $ (9.4)
Underfunded Accumulated Benefit Obligation	AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Accumulated Benefit Obligation $ 55.6 $ 2.5 $ 0.3 $ 1.2 $ 0.1 $ 1.2 $ 235.1 Fair Value of Plan Assets — — — — — — 231.3 Underfunded Accumulated Benefit Obligation as of December 31, 2022 $ (55.6) $ (2.5) $ (0.3) $ (1.2) $ (0.1) $ (1.2) $ (3.8) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Accumulated Benefit Obligation $ 69.7 $ 3.3 $ 0.4 $ 1.2 $ 0.3 $ 1.5 $ 1.3 Fair Value of Plan Assets — — — — — — — Underfunded Accumulated Benefit Obligation as of December 31, 2021 $ (69.7) $ (3.3) $ (0.4) $ (1.2) $ (0.3) $ (1.5) $ (1.3)
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans OPEB (in millions) AEP $ 6.3 $ 3.1 AEP Texas 0.4 0.1 APCo — 1.6 I&M 0.1 — PSO 0.1 — SWEPCo 0.1 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2023 $ 369.0 $ 35.4 $ 43.7 $ 38.1 $ 32.3 $ 19.2 $ 24.2 2024 373.6 36.3 43.6 39.8 31.9 18.9 25.1 2025 368.8 35.2 42.5 40.7 32.4 19.0 25.3 2026 369.6 35.0 43.0 40.4 32.0 19.2 25.5 2027 364.3 32.6 41.8 41.0 31.6 18.4 25.4 Years 2028 to 2032, in Total 1,702.3 138.9 202.1 196.4 146.0 81.1 107.9 OPEB Benefit Payments AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2023 $ 116.0 $ 9.1 $ 19.0 $ 14.9 $ 12.6 $ 6.7 $ 7.5 2024 117.6 9.5 19.3 15.0 12.6 6.9 7.8 2025 126.9 10.4 20.5 16.1 13.5 7.4 8.5 2026 127.4 10.6 20.4 16.3 13.4 7.3 8.6 2027 126.8 10.6 20.3 16.1 13.3 7.1 8.5 Years 2028 to 2032, in Total 604.0 48.5 95.8 75.1 62.3 32.2 41.2 OPEB Medicare AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) 2023 $ 0.2 $ — $ 0.1 $ — $ — $ — $ — 2024 0.3 — 0.1 — — — — 2025 0.3 — 0.1 — — — — 2026 0.3 — 0.1 — — — — 2027 0.3 — 0.1 — — — — Years 2028 to 2032, in Total 1.6 — 0.5 — — — —
Components of Net Periodic Benefit Cost	AEP Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 123.1 $ 129.2 $ 111.9 $ 7.4 $ 9.5 $ 10.0 Interest Cost 148.2 137.2 167.9 29.2 30.5 39.8 Expected Return on Plan Assets (253.4) (229.7) (264.9) (110.0) (91.1) (95.6) Amortization of Prior Service Credit — — — (71.4) (70.9) (69.8) Amortization of Net Actuarial Loss 63.0 101.5 93.7 — — 5.9 Settlements — — — — — — Net Periodic Benefit Cost (Credit) 80.9 138.2 108.6 (144.8) (122.0) (109.7) Capitalized Portion (53.8) (55.7) (47.0) (3.2) (4.1) (4.2) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 27.1 $ 82.5 $ 61.6 $ (148.0) $ (126.1) $ (113.9) AEP Texas Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 11.1 $ 11.8 $ 10.0 $ 0.5 $ 0.7 $ 0.8 Interest Cost 12.1 11.2 13.9 2.2 2.4 3.2 Expected Return on Plan Assets (21.0) (19.5) (22.7) (9.1) (7.5) (8.0) Amortization of Prior Service Credit — — — (6.1) (6.0) (5.9) Amortization of Net Actuarial Loss 5.2 8.3 7.8 — — 0.5 Net Periodic Benefit Cost (Credit) 7.4 11.8 9.0 (12.5) (10.4) (9.4) Capitalized Portion (6.2) (6.6) (5.5) (0.3) (0.4) (0.4) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 1.2 $ 5.2 $ 3.5 $ (12.8) $ (10.8) $ (9.8) APCo Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 11.4 $ 11.9 $ 10.5 $ 0.8 $ 1.0 $ 1.0 Interest Cost 17.5 16.4 20.3 4.7 4.9 6.6 Expected Return on Plan Assets (32.3) (29.1) (33.6) (16.3) (13.5) (14.4) Amortization of Prior Service Credit — — — (10.4) (10.3) (10.2) Amortization of Net Actuarial Loss 7.4 12.0 11.2 — — 0.9 Net Periodic Benefit Cost (Credit) 4.0 11.2 8.4 (21.2) (17.9) (16.1) Capitalized Portion (5.0) (5.2) (4.5) (0.4) (0.4) (0.4) Net Periodic Benefit Cost (Credit) Recognized in Expense $ (1.0) $ 6.0 $ 3.9 $ (21.6) $ (18.3) $ (16.5) I&M Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 16.2 $ 17.5 $ 15.4 $ 0.9 $ 1.3 $ 1.4 Interest Cost 17.0 16.2 19.7 3.4 3.5 4.7 Expected Return on Plan Assets (32.4) (28.9) (33.3) (13.7) (11.1) (11.7) Amortization of Prior Service Credit — — — (9.7) (9.6) (9.5) Amortization of Net Actuarial Loss 7.1 11.7 10.8 — — 0.7 Net Periodic Benefit Cost (Credit) 7.9 16.5 12.6 (19.1) (15.9) (14.4) Capitalized Portion (4.6) (4.9) (4.3) (0.3) (0.4) (0.4) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 3.3 $ 11.6 $ 8.3 $ (19.4) $ (16.3) $ (14.8) OPCo Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 11.2 $ 11.4 $ 9.7 $ 0.6 $ 0.8 $ 0.9 Interest Cost 13.3 12.5 15.4 3.0 3.0 4.2 Expected Return on Plan Assets (24.8) (22.3) (26.3) (12.0) (9.7) (10.5) Amortization of Prior Service Credit — — — (7.1) (7.2) (7.0) Amortization of Net Actuarial Loss 5.5 9.1 8.5 — — 0.7 Net Periodic Benefit Cost (Credit) 5.2 10.7 7.3 (15.5) (13.1) (11.7) Capitalized Portion (6.1) (6.2) (5.0) (0.3) (0.4) (0.5) Net Periodic Benefit Cost (Credit) Recognized in Expense $ (0.9) $ 4.5 $ 2.3 $ (15.8) $ (13.5) $ (12.2) PSO Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 7.4 $ 8.0 $ 7.3 $ 0.4 $ 0.6 $ 0.7 Interest Cost 7.0 6.7 8.5 1.5 1.6 2.1 Expected Return on Plan Assets (13.4) (12.3) (14.5) (6.1) (5.0) (5.2) Amortization of Prior Service Credit — — — (4.4) (4.4) (4.4) Amortization of Net Actuarial Loss 2.9 4.9 4.7 — — 0.3 Net Periodic Benefit Cost (Credit) 3.9 7.3 6.0 (8.6) (7.2) (6.5) Capitalized Portion (3.2) (3.4) (2.8) (0.2) (0.3) (0.3) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 0.7 $ 3.9 $ 3.2 $ (8.8) $ (7.5) $ (6.8) SWEPCo Pension Plans OPEB Years Ended December 31, 2022 2021 2020 2022 2021 2020 (in millions) Service Cost $ 10.6 $ 11.2 $ 9.9 $ 0.6 $ 0.8 $ 0.8 Interest Cost 9.1 8.5 10.2 1.8 1.9 2.5 Expected Return on Plan Assets (14.6) (13.5) (15.7) (7.3) (6.1) (6.3) Amortization of Prior Service Credit — — — (5.3) (5.3) (5.2) Amortization of Net Actuarial Loss 3.8 6.2 5.7 — — 0.4 Net Periodic Benefit Cost (Credit) 8.9 12.4 10.1 (10.2) (8.7) (7.8) Capitalized Portion (4.0) (4.1) (3.4) (0.2) (0.3) (0.3) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 4.9 $ 8.3 $ 6.7 $ (10.4) $ (9.0) $ (8.1)
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2022 2021 2020 (in millions) AEP $ 81.9 $ 79.9 $ 81.8 AEP Texas 6.5 6.4 6.4 APCo 7.8 7.6 7.7 I&M 11.1 10.9 11.3 OPCo 7.7 7.2 7.3 PSO 4.7 4.6 4.9 SWEPCo 6.4 6.4 6.7
Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans OPEB December 31, Assumption 2022 2021 2022 2021 Discount Rate 5.50 % 2.90 % 5.50 % 2.90 % Interest Crediting Rate 4.25 % 4.00 % NA NA NA Not applicable. Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2022 2021 AEP 5.05 % 5.10 % AEP Texas 5.15 % 5.10 % APCo 4.90 % 4.85 % I&M 5.00 % 5.00 % OPCo 5.35 % 5.30 % PSO 5.15 % 5.10 % SWEPCo 5.00 % 4.95 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member]
Actuarial Assumptions	Pension Plans OPEB Year Ended December 31, Assumption 2022 2021 2020 2022 2021 2020 Discount Rate 2.90 % 2.50 % 3.25 % 2.90 % 2.55 % 3.30 % Interest Crediting Rate 4.00 % 4.00 % 4.00 % NA NA NA Expected Return on Plan Assets 5.25 % 4.75 % 5.75 % 5.50 % 4.75 % 5.50 % NA Not applicable. Pension Plans Year Ended December 31, Assumption – Rate of Compensation Increase (a) 2022 2021 2020 AEP 5.05 % 5.10 % 5.00 % AEP Texas 5.15 % 5.10 % 5.05 % APCo 4.90 % 4.85 % 4.85 % I&M 5.00 % 5.00 % 5.00 % OPCo 5.35 % 5.30 % 5.25 % PSO 5.15 % 5.10 % 5.05 % SWEPCo 5.00 % 4.95 % 4.90 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Pension Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities (a): Domestic $ 347.6 $ — $ — $ — $ 347.6 8.4 % International 398.4 — — — 398.4 9.7 % Common Collective Trusts (b) — — — 379.9 379.9 9.2 % Subtotal – Equities 746.0 — — 379.9 1,125.9 27.3 % Fixed Income (a): United States Government and Agency Securities (0.6) 1,071.4 — — 1,070.8 26.0 % Corporate Debt — 891.7 — — 891.7 21.6 % Foreign Debt — 140.2 — — 140.2 3.4 % State and Local Government — 37.0 — — 37.0 0.9 % Other – Asset Backed — 0.8 — — 0.8 — % Subtotal – Fixed Income (0.6) 2,141.1 — — 2,140.5 51.9 % Infrastructure (b) — — — 109.2 109.2 2.6 % Real Estate (b) — — — 276.9 276.9 6.7 % Alternative Investments (b) — — — 319.7 319.7 7.8 % Cash and Cash Equivalents (b) — 64.9 — 58.3 123.2 3.0 % Other – Pending Transactions and Accrued Income (c) — — — 29.3 29.3 0.7 % Total $ 745.4 $ 2,206.0 $ — $ 1,173.3 $ 4,124.7 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (c) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities (a): Domestic $ 388.9 $ — $ — $ — $ 388.9 7.2 % International 465.7 — — — 465.7 8.7 % Common Collective Trusts (b) — — — 463.9 463.9 8.7 % Subtotal – Equities 854.6 — — 463.9 1,318.5 24.6 % Fixed Income (a): United States Government and Agency Securities 0.1 1,557.6 — — 1,557.7 29.1 % Corporate Debt — 1,295.9 — — 1,295.9 24.2 % Foreign Debt — 259.4 — — 259.4 4.8 % State and Local Government — 57.1 — — 57.1 1.1 % Other – Asset Backed — 1.3 — — 1.3 — % Subtotal – Fixed Income 0.1 3,171.3 — — 3,171.4 59.2 % Infrastructure (b) — — — 92.1 92.1 1.7 % Real Estate (b) — — — 232.6 232.6 4.4 % Alternative Investments (b) — — — 448.8 448.8 8.4 % Cash and Cash Equivalents (b) — 64.3 — 53.4 117.7 2.2 % Other – Pending Transactions and Accrued Income (c) — — — (28.2) (28.2) (0.5) % Total $ 854.7 $ 3,235.6 $ — $ 1,262.6 $ 5,352.9 100.0 % (a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (c) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Other Postretirement Benefit Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 414.1 $ — $ — $ — $ 414.1 26.7 % International 265.0 — — — 265.0 17.1 % Common Collective Trusts (a) — — — 169.1 169.1 10.9 % Subtotal – Equities 679.1 — — 169.1 848.2 54.7 % Fixed Income: Common Collective Trust – Debt (a) — — — 120.3 120.3 7.8 % United States Government and Agency Securities 0.1 155.8 — — 155.9 10.1 % Corporate Debt — 141.5 — — 141.5 9.1 % Foreign Debt — 21.0 — — 21.0 1.4 % State and Local Government 62.9 7.8 — — 70.7 4.6 % Subtotal – Fixed Income 63.0 326.1 — 120.3 509.4 33.0 % Trust Owned Life Insurance: International Equities — 46.7 — — 46.7 3.0 % United States Bonds — 110.3 — — 110.3 7.1 % Subtotal – Trust Owned Life Insurance — 157.0 — — 157.0 10.1 % Cash and Cash Equivalents (a) 23.2 — — 6.7 29.9 1.9 % Other – Pending Transactions and Accrued Income (b) — — — 4.8 4.8 0.3 % Total $ 765.3 $ 483.1 $ — $ 300.9 $ 1,549.3 100.0 % (a) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 474.0 $ — $ — $ — $ 474.0 23.2 % International 296.3 — — — 296.3 14.5 % Common Collective Trusts (a) — — — 265.0 265.0 13.0 % Subtotal – Equities 770.3 — — 265.0 1,035.3 50.7 % Fixed Income: Common Collective Trust – Debt (a) — — — 167.7 167.7 8.2 % United States Government and Agency Securities — 222.4 — — 222.4 10.9 % Corporate Debt — 233.2 — — 233.2 11.4 % Foreign Debt — 39.8 — — 39.8 2.0 % State and Local Government 91.9 13.6 — — 105.5 5.1 % Subtotal – Fixed Income 91.9 509.0 — 167.7 768.6 37.6 % Trust Owned Life Insurance: International Equities — 23.4 — — 23.4 1.1 % United States Bonds — 171.3 — — 171.3 8.4 % Subtotal – Trust Owned Life Insurance — 194.7 — — 194.7 9.5 % Cash and Cash Equivalents (a) 33.0 — — 6.7 39.7 1.9 % Other – Pending Transactions and Accrued Income (b) — — — 6.0 6.0 0.3 % Total $ 895.2 $ 703.7 $ — $ 445.4 $ 2,044.3 100.0 % (a) Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
Business Segments (Tables)	Dec. 31, 2022
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) (as adjusted) 2022 Revenues from: External Customers $ 11,292.8 $ 5,489.6 $ 357.5 $ 2,448.9 $ 50.7 $ — $ 19,639.5 Other Operating Segments 184.7 22.4 1,319.5 18.0 59.2 (1,603.8) — Total Revenues $ 11,477.5 $ 5,512.0 $ 1,677.0 $ 2,466.9 $ 109.9 $ (1,603.8) $ 19,639.5 Loss on the Expected Sale of the Kentucky Operations $ — $ — $ — $ — $ 363.3 $ — $ 363.3 Asset Impairments and Other Related Charges 24.9 — — — 23.9 — 48.8 Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset (37.0) — — — — — (37.0) Gain on Sale of Mineral Rights — — — (116.3) — — (116.3) Depreciation and Amortization 2,007.2 746.7 355.0 93.0 0.9 — 3,202.8 Interest Expense 650.9 328.0 169.3 51.8 308.9 (112.8) 1,396.1 Income Tax Expense (Benefit) (93.8) 116.9 193.6 (83.1) (128.2) — 5.4 Equity Earnings (Loss) of Unconsolidated Subsidiaries 1.4 0.6 83.4 (192.4) (2.4) — (109.4) Net Income (Loss) $ 1,296.2 $ 595.7 $ 676.8 $ 274.5 $ (537.6) $ — $ 2,305.6 Gross Property Additions $ 4,164.6 $ 2,177.3 $ 1,470.8 $ 69.2 $ 25.9 $ (28.8) $ 7,879.0 Total Assets $ 49,761.8 $ 22,920.2 $ 15,215.8 $ 4,520.1 $ 6,768.4 (b) $ (5,783.0) (c) $ 93,403.3 Investments in Equity Method Investees $ 10.1 $ 3.0 $ 858.3 $ 337.6 $ 67.7 $ — $ 1,276.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2021 Revenues from: External Customers $ 9,852.2 $ 4,464.1 $ 351.1 $ 2,108.3 $ 16.3 $ — $ 16,792.0 Other Operating Segments 146.3 28.8 1,175.1 55.4 55.9 (1,461.5) — Total Revenues $ 9,998.5 $ 4,492.9 $ 1,526.2 $ 2,163.7 $ 72.2 $ (1,461.5) $ 16,792.0 Asset Impairments and Other Related Charges $ 11.6 $ — $ — $ — $ — $ — $ 11.6 Depreciation and Amortization 1,747.6 690.3 306.0 80.9 0.9 — 2,825.7 Interest Expense 574.2 300.9 146.3 15.6 180.8 (18.7) 1,199.1 Income Tax Expense (Benefit) (11.2) 77.5 159.6 (48.8) (61.6) — 115.5 Equity Earnings (Loss) of Unconsolidated Subsidiaries 3.4 — 75.0 (10.6) 23.9 — 91.7 Net Income (Loss) $ 1,116.7 $ 543.4 $ 682.0 $ 210.2 $ (64.2) $ — $ 2,488.1 Gross Property Additions $ 2,963.1 $ 1,766.0 $ 1,468.6 $ 232.8 $ 25.5 $ (29.2) $ 6,426.8 Total Assets $ 46,974.2 $ 21,120.2 $ 13,873.3 $ 4,263.6 $ 5,846.5 (b) $ (4,409.1) (c) $ 87,668.7 Investments in Equity Method Investees $ 33.5 $ 2.5 $ 830.4 $ 487.8 $ 93.3 $ — $ 1,447.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) 2020 Revenues from: External Customers $ 8,753.2 $ 4,238.7 $ 297.4 $ 1,621.0 $ 8.2 $ — $ 14,918.5 Other Operating Segments 126.2 107.2 901.4 104.6 88.6 (1,328.0) — Total Revenues $ 8,879.4 $ 4,345.9 $ 1,198.8 $ 1,725.6 $ 96.8 $ (1,328.0) $ 14,918.5 Depreciation and Amortization $ 1,600.5 $ 751.1 $ 257.6 $ 72.8 $ 0.8 $ — $ 2,682.8 Interest Expense 565.0 289.2 133.2 24.0 196.4 (42.1) 1,165.7 Income Tax Expense (Benefit) (7.0) 29.7 130.8 (108.0) (5.0) — 40.5 Equity Earnings of Unconsolidated Subsidiaries 2.9 — 82.4 3.2 2.6 — 91.1 Net Income (Loss) $ 1,064.5 $ 496.4 $ 508.5 $ 216.9 $ (89.6) $ — $ 2,196.7 Gross Property Additions $ 2,291.2 $ 2,108.1 $ 1,649.3 $ 197.0 $ 16.0 $ (15.3) $ 6,246.3 Investments in Equity Method Investees $ 37.1 $ 2.1 $ 831.3 $ 467.0 $ 68.8 $ — $ 1,406.3 (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, interest expense and other nonallocated costs. (b) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (c) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo 2022 (in millions) Revenues from: External Customers $ 340.9 $ — $ — $ 340.9 Sales to AEP Affiliates 1,283.8 — — 1,283.8 Other Revenues (0.2) — — (0.2) Total Revenues $ 1,624.5 $ — $ — $ 1,624.5 Depreciation and Amortization $ 346.2 $ — $ — $ 346.2 Interest Income 0.7 177.8 (176.9) (a) 1.6 Allowance for Equity Funds Used During Construction 70.7 — — 70.7 Interest Expense 162.5 177.1 (176.9) (a) 162.7 Income Tax Expense 169.1 — — 169.1 Net Income $ 594.2 $ — (b) $ — $ 594.2 Gross Property Additions $ 1,468.3 $ — $ — $ 1,468.3 Total Assets $ 13,875.6 $ 4,817.4 (c) $ (4,878.8) (d) $ 13,814.2 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo 2021 (in millions) Revenues from: External Customers $ 315.1 $ — $ — $ 315.1 Sales to AEP Affiliates 1,153.9 — — 1,153.9 Other Revenues 0.3 — — 0.3 Total Revenues $ 1,469.3 $ — $ — $ 1,469.3 Depreciation and Amortization $ 297.3 $ — $ — $ 297.3 Interest Income 0.1 158.1 (157.7) (a) 0.5 Allowance for Equity Funds Used During Construction 67.2 — — 67.2 Interest Expense 141.2 157.7 (157.7) (a) 141.2 Income Tax Expense 144.1 — — 144.1 Net Income $ 591.5 $ 0.2 (b) $ — $ 591.7 Gross Property Additions $ 1,442.7 $ — $ — $ 1,442.7 Total Assets $ 12,564.3 $ 4,389.5 (c) $ (4,429.4) (d) $ 12,524.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo 2020 (in millions) Revenues from: External Customers $ 248.8 $ — $ — $ 248.8 Sales to AEP Affiliates 896.3 — — 896.3 Other Revenue 0.6 — — 0.6 Total Revenues $ 1,145.7 $ — $ — $ 1,145.7 Depreciation and Amortization $ 249.0 $ — $ — $ 249.0 Interest Income 0.9 149.6 (148.1) (a) 2.4 Allowance for Equity Funds Used During Construction 74.0 — — 74.0 Interest Expense 127.8 148.1 (148.1) (a) 127.8 Income Tax Expense 106.5 0.2 — 106.7 Net Income $ 422.3 $ 1.1 (b) $ — $ 423.4 Gross Property Additions $ 1,621.9 $ — $ — $ 1,621.9 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Primarily relates to Notes Receivable from the State Transcos. (d) Primarily relates to elimination of Notes Receivable from the State Transcos.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	12 Months Ended
Derivatives and Hedging (Tables)	Dec. 31, 2022
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2022 Primary Risk Unit of AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 226.8 — 17.9 4.2 2.5 2.9 2.2 Natural Gas MMBtus 77.1 — 1.9 — — 1.9 2.1 Heating Oil and Gasoline Gallons 6.9 1.9 1.0 0.7 1.4 0.9 1.0 Interest Rate USD $ 99.9 $ — $ — $ — $ — $ — $ — Interest Rate on Long-term Debt USD $ 1,650.0 $ — $ — $ — $ — $ 200.0 $ — December 31, 2021 Primary Risk Unit of AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 287.9 — 33.1 13.6 2.7 11.9 3.4 Natural Gas MMBtus 34.1 — — — — 1.3 5.1 Heating Oil and Gasoline Gallons 7.4 1.9 1.1 0.7 1.5 0.8 1.0 Interest Rate USD $ 116.5 $ — $ — $ — $ — $ — $ — Interest Rate on Long-term Debt USD $ 950.0 $ — $ — $ — $ — $ — $ —
Fair Value of Derivative Instruments	AEP December 31, 2022 Risk Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 965.4 $ 212.2 $ 1.8 $ 1,179.4 $ (830.6) $ 348.8 Long-term Risk Management Assets 565.6 148.9 14.3 728.8 (444.7) 284.1 Total Assets 1,531.0 361.1 16.1 1,908.2 (1,275.3) 632.9 Current Risk Management Liabilities 663.8 60.4 41.4 765.6 (620.4) 145.2 Long-term Risk Management Liabilities 412.0 17.4 91.1 520.5 (175.3) 345.2 Total Liabilities 1,075.8 77.8 132.5 1,286.1 (795.7) 490.4 Total MTM Derivative Contract Net Assets (Liabilities) (d) $ 455.2 $ 283.3 $ (116.4) $ 622.1 $ (479.6) $ 142.5 December 31, 2021 Risk Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 520.9 $ 176.0 $ 1.2 $ 698.1 $ (497.7) $ 200.4 Long-term Risk Management Assets 370.5 89.1 — 459.6 (192.6) 267.0 Total Assets 891.4 265.1 1.2 1,157.7 (690.3) 467.4 Current Risk Management Liabilities 397.2 40.9 — 438.1 (362.6) 75.5 Long-term Risk Management Liabilities 243.9 16.7 38.1 298.7 (68.4) 230.3 Total Liabilities 641.1 57.6 38.1 736.8 (431.0) 305.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 250.3 $ 207.5 $ (36.9) $ 420.9 $ (259.3) $ 161.6 AEP Texas December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ — $ — $ — December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 0.6 $ (0.6) $ — Long-term Risk Management Assets — — — Total Assets 0.6 (0.6) — Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.6 $ (0.6) $ — APCo December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 69.3 $ (0.2) $ 69.1 Long-term Risk Management Assets 0.7 (0.7) — Total Assets 70.0 (0.9) 69.1 Current Risk Management Liabilities 4.1 (0.5) 3.6 Long-term Risk Management Liabilities 0.7 (0.6) 0.1 Total Liabilities 4.8 (1.1) 3.7 Total MTM Derivative Contract Net Assets (d) $ 65.2 $ 0.2 $ 65.4 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 47.5 $ (5.5) $ 42.0 Long-term Risk Management Assets 0.2 (0.2) — Total Assets 47.7 (5.7) 42.0 Current Risk Management Liabilities 7.2 (6.4) 0.8 Long-term Risk Management Liabilities 0.2 (0.2) — Total Liabilities 7.4 (6.6) 0.8 Total MTM Derivative Contract Net Assets $ 40.3 $ 0.9 $ 41.2 I&M December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 16.0 $ (0.8) $ 15.2 Long-term Risk Management Assets 0.5 (0.3) 0.2 Total Assets 16.5 (1.1) 15.4 Current Risk Management Liabilities 0.9 (0.9) — Long-term Risk Management Liabilities 0.3 (0.3) — Total Liabilities 1.2 (1.2) — Total MTM Derivative Contract Net Assets (d) $ 15.3 $ 0.1 $ 15.4 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 11.1 $ (7.8) $ 3.3 Long-term Risk Management Assets 0.2 (0.2) — Total Assets 11.3 (8.0) 3.3 Current Risk Management Liabilities 14.8 (9.8) 5.0 Long-term Risk Management Liabilities 0.2 (0.2) — Total Liabilities 15.0 (10.0) 5.0 Total MTM Derivative Contract Net Assets (Liabilities) $ (3.7) $ 2.0 $ (1.7) OPCo December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 2.1 (0.3) 1.8 Long-term Risk Management Liabilities 37.9 — 37.9 Total Liabilities 40.0 (0.3) 39.7 Total MTM Derivative Net Assets (Liabilities) (d) $ (40.0) $ 0.3 $ (39.7) December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 0.5 $ (0.5) $ — Long-term Risk Management Assets — — — Total Assets 0.5 (0.5) — Current Risk Management Liabilities 6.7 — 6.7 Long-term Risk Management Liabilities 85.8 — 85.8 Total Liabilities 92.5 — 92.5 Total MTM Derivative Contract Net Liabilities $ (92.0) $ (0.5) $ (92.5) PSO December 31, 2022 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) Interest Rate (a) (in millions) Current Risk Management Assets $ 24.1 $ 1.6 $ 25.7 $ (0.4) $ 25.3 Long-term Risk Management Assets — — — — — Total Assets 24.1 1.6 25.7 (0.4) 25.3 Current Risk Management Liabilities 2.1 — 2.1 (0.5) 1.6 Long-term Risk Management Liabilities — — — — — Total Liabilities 2.1 — 2.1 (0.5) 1.6 Total MTM Derivative Contract Net Assets (d) $ 22.0 $ 1.6 $ 23.6 $ 0.1 $ 23.7 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 12.4 $ (0.3) $ 12.1 Long-term Risk Management Assets — — — Total Assets 12.4 (0.3) 12.1 Current Risk Management Liabilities 3.7 — 3.7 Long-term Risk Management Liabilities — — — Total Liabilities 3.7 — 3.7 Total MTM Derivative Contract Net Assets (Liabilities) $ 8.7 $ (0.3) $ 8.4 SWEPCo December 31, 2022 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 16.8 $ (0.4) $ 16.4 Long-term Risk Management Assets — — — Total Assets 16.8 (0.4) 16.4 Current Risk Management Liabilities 2.0 (0.6) 1.4 Long-term Risk Management Liabilities — — — Total Liabilities 2.0 (0.6) 1.4 Total MTM Derivative Contract Net Assets (d) $ 14.8 $ 0.2 $ 15.0 December 31, 2021 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement of Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c) (in millions) Current Risk Management Assets $ 10.1 $ (0.3) $ 9.8 Long-term Risk Management Assets 1.1 — 1.1 Total Assets 11.2 (0.3) 10.9 Current Risk Management Liabilities 2.1 — 2.1 Long-term Risk Management Liabilities — — — Total Liabilities 2.1 — 2.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 9.1 $ (0.3) $ 8.8 (a) Derivative instruments within these categories are disclosed as 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. (d) Increase in amounts as of December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2022 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 11.1 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 313.8 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.5 10.6 — — — Purchased Electricity for Resale 5.0 — 4.5 0.1 — 0.2 — Other Operation 4.8 1.5 0.4 0.5 0.8 0.6 0.8 Maintenance 6.7 1.8 0.9 0.6 1.2 0.8 1.1 Regulatory Assets (a) 52.6 0.1 (0.1) (0.8) 52.1 3.6 (2.1) Regulatory Liabilities (a) 299.7 (0.6) 82.4 8.6 3.7 98.5 77.9 Total Gain on Risk Management Contracts (b) $ 693.7 $ 2.8 $ 88.6 $ 19.6 $ 57.8 $ 103.7 $ 77.7 Year Ended December 31, 2021 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (0.6) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 169.1 — — — — — — Electric Generation, Transmission and Distribution Revenues — — (0.5) (0.1) — — — Purchased Electricity for Resale 2.0 — 1.8 — — — — Other Operation 2.8 0.8 0.3 0.3 0.5 0.3 0.4 Maintenance 3.4 1.0 0.5 0.3 0.6 0.4 0.5 Regulatory Assets (a) (9.1) — (2.7) (14.8) 10.0 (3.6) 3.6 Regulatory Liabilities (a) 156.4 0.2 55.9 (3.9) — 48.9 37.0 Total Gain (Loss) on Risk Management Contracts $ 324.0 $ 2.0 $ 55.3 $ (18.2) $ 11.1 $ 46.0 $ 41.5 Year Ended December 31, 2020 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.8 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 9.5 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 0.4 0.1 — — 0.1 Purchased Electricity for Resale 1.4 — 1.2 0.1 — — — Other Operation (2.0) (0.6) (0.2) (0.2) (0.3) (0.2) (0.3) Maintenance (2.9) (0.8) (0.4) (0.3) (0.5) (0.3) (0.4) Regulatory Assets (a) (4.8) — — (0.1) (6.6) — 1.4 Regulatory Liabilities (a) 114.9 0.4 20.3 12.4 12.4 39.1 20.2 Total Gain (Loss) on Risk Management Contracts $ 116.9 $ (1.0) $ 21.3 $ 12.0 $ 5.0 $ 38.6 $ 21.0 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. (b) Increase in amounts for the year ended December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.
Impact of Fair Value Hedges on Balance Sheet	Carrying Amount of the Hedged Liabilities Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (in millions) Long-term Debt (a) (b) $ (855.5) $ (952.3) $ 89.7 $ (8.5) (a) Amounts included on the Balance Sheet within Current and Noncurrent Liabilities line items Long-term Debt Due within One Year and Long-term Debt, respectively. (b) Amounts include $(38) million and $(46) million as of December 31, 2022 and 2021, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.
Gain (Loss) on Hedging Instruments	Years Ended December 31, 2022 2021 2020 (in millions) Gain (Loss) on Interest Rate Contracts: Fair Value Hedging Instruments (a) $ (90.4) $ (35.5) $ 41.1 Fair Value Portion of Long-term Debt (a) 90.4 35.5 (41.1) (a) Gain (Loss) is included in Interest Expense on the statements of income.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2022 December 31, 2021 Commodity Interest Rate Commodity Interest Rate (in millions) AOCI Gain (Loss) Net of Tax $ 223.5 $ 0.3 $ 163.7 $ (21.3) Portion Expected to be Reclassed to Net Income During the Next Twelve Months 119.9 0.3 106.7 (3.3) Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2022 December 31, 2021 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 $ (0.3) $ (0.2) $ (1.3) $ (1.1) APCo 6.7 0.8 7.5 0.8 I&M (5.1) (0.6) (6.7) (1.6) PSO 1.3 0.1 — — SWEPCo 1.1 0.2 1.2 0.1

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2022
Book Values and Fair Values of Long-term Debt	December 31, 2022 2021 Company Book Value Fair Value Book Value Fair Value (in millions) AEP (a) $ 36,801.0 $ 32,915.9 $ 34,557.6 $ 38,789.3 AEP Texas 5,657.8 5,045.8 5,180.8 5,663.8 AEPTCo 4,782.8 3,940.5 4,343.9 4,968.2 APCo 5,410.5 5,079.2 4,938.9 6,037.1 I&M 3,260.8 2,929.0 3,195.0 3,748.0 OPCo 2,970.3 2,516.6 2,968.5 3,437.5 PSO 1,912.8 1,635.8 1,913.5 2,163.7 SWEPCo 3,391.6 2,870.9 3,395.2 3,792.9 (a) The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $877 million and $1.7 billion as of December 31, 2022 and 2021, respectively. See “Equity Units” section of Note 14 for additional information.
Other Temporary Investments	December 31, 2022 Gross Gross Unrealized Unrealized Fair Other Temporary Investments and Restricted Cash Cost Gains Losses Value (in millions) Restricted Cash (a) $ 47.1 $ — $ — $ 47.1 Other Cash Deposits 9.0 — — 9.0 Fixed Income Securities – Mutual Funds (b) 152.4 — (8.3) 144.1 Equity Securities – Mutual Funds 15.1 19.4 — 34.5 Total Other Temporary Investments and Restricted Cash $ 223.6 $ 19.4 $ (8.3) $ 234.7 December 31, 2021 Gross Gross Unrealized Unrealized Fair Other Temporary Investments and Restricted Cash Cost Gains Losses Value (in millions) Restricted Cash (a) $ 48.0 $ — $ — $ 48.0 Other Cash Deposits 10.0 — — 10.0 Fixed Income Securities – Mutual Funds (b) 154.3 0.5 — 154.8 Equity Securities – Mutual Funds 19.7 35.9 — 55.6 Total Other Temporary Investments and Restricted Cash $ 232.0 $ 36.4 $ — $ 268.4 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
Debt and Equity Securities Within Other Temporary Investments	Years Ended December 31, 2022 2021 2020 (in millions) Proceeds from Investment Sales $ 30.2 $ 15.0 $ 50.9 Purchases of Investments 18.8 26.9 41.6 Gross Realized Gains on Investment Sales 6.1 3.6 3.8 Gross Realized Losses on Investment Sales 1.3 — 0.2
Nuclear Trust Fund Investments	December 31, 2022 2021 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 21.2 $ — $ — $ 84.7 $ — $ — Fixed Income Securities: United States Government 1,123.8 (3.1) (18.8) 1,156.4 66.3 (7.9) Corporate Debt 61.6 (7.0) (9.6) 76.7 6.7 (2.1) State and Local Government 3.3 0.1 (0.1) 7.3 0.4 (0.1) Subtotal Fixed Income Securities 1,188.7 (10.0) (28.5) 1,240.4 73.4 (10.1) Equity Securities - Domestic (a) 2,131.3 1,477.3 — 2,541.9 1,901.3 — Spent Nuclear Fuel and Decommissioning Trusts $ 3,341.2 $ 1,467.3 $ (28.5) $ 3,867.0 $ 1,974.7 $ (10.1) (a) Amount reported as Gross Unrealized Gains includes unrealized gains of $1.5 billion and $1.9 billion and unrealized losses of $6 million and $4 million as of December 31, 2022 and 2021, respectively.
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2022 2021 2020 (in millions) Proceeds from Investment Sales $ 2,713.6 $ 1,886.4 $ 1,593.4 Purchases of Investments 2,765.4 1,928.2 1,637.2 Gross Realized Gains on Investment Sales 52.4 103.2 26.4 Gross Realized Losses on Investment Sales 42.6 16.5 26.1
Contractual Maturities, Fair Value of Debt Securities	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 365.2 After 1 year through 5 years 425.4 After 5 years through 10 years 203.0 After 10 years 195.1 Total $ 1,188.7
Fair Value, Assets and Liabilities Measured on Recurring Basis	AEP December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments and Restricted Cash Restricted Cash $ 47.1 $ — $ — $ — $ 47.1 Other Cash Deposits (a) — — — 9.0 9.0 Fixed Income Securities – Mutual Funds 144.1 — — — 144.1 Equity Securities – Mutual Funds (b) 34.5 — — — 34.5 Total Other Temporary Investments and Restricted Cash 225.7 — — 9.0 234.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 15.0 1,197.5 314.4 (1,211.5) 315.4 Cash Flow Hedges: Commodity Hedges (c) — 332.6 26.7 (52.8) 306.5 Interest Rate Hedges — 11.0 — — 11.0 Total Risk Management Assets 15.0 1,541.1 341.1 (1,264.3) 632.9 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 11.3 — — 9.9 21.2 Fixed Income Securities: United States Government — 1,123.8 — — 1,123.8 Corporate Debt — 61.6 — — 61.6 State and Local Government — 3.3 — — 3.3 Subtotal Fixed Income Securities — 1,188.7 — — 1,188.7 Equity Securities – Domestic (b) 2,131.3 — — — 2,131.3 Total Spent Nuclear Fuel and Decommissioning Trusts 2,142.6 1,188.7 — 9.9 3,341.2 Total Assets $ 2,383.3 $ 2,729.8 $ 341.1 $ (1,245.4) $ 4,208.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 21.8 $ 870.9 $ 179.0 $ (731.9) $ 339.8 Cash Flow Hedges: Commodity Hedges (c) — 74.3 1.7 (52.8) 23.2 Fair Value Hedges — 127.4 — — 127.4 Total Risk Management Liabilities $ 21.8 $ 1,072.6 $ 180.7 $ (784.7) $ 490.4 AEP December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments and Restricted Cash Restricted Cash $ 48.0 $ — $ — $ — $ 48.0 Other Cash Deposits (a) — — — 10.0 10.0 Fixed Income Securities – Mutual Funds 154.8 — — — 154.8 Equity Securities – Mutual Funds (b) 55.6 — — — 55.6 Total Other Temporary Investments and Restricted Cash 258.4 — — 10.0 268.4 Risk Management Assets Risk Management Commodity Contracts (c) (f) 7.4 649.6 232.7 (643.9) 245.8 Cash Flow Hedges: Commodity Hedges (c) — 242.9 19.2 (41.7) 220.4 Fair Value Hedges — 1.2 — — 1.2 Total Risk Management Assets 7.4 893.7 251.9 (685.6) 467.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 77.7 — — 7.0 84.7 Fixed Income Securities: United States Government — 1,156.4 — — 1,156.4 Corporate Debt — 76.7 — — 76.7 State and Local Government — 7.3 — — 7.3 Subtotal Fixed Income Securities — 1,240.4 — — 1,240.4 Equity Securities – Domestic (b) 2,541.9 — — — 2,541.9 Total Spent Nuclear Fuel and Decommissioning Trusts 2,619.6 1,240.4 — 7.0 3,867.0 Other Investments (h) 28.8 14.9 — — 43.7 Total Assets $ 2,914.2 $ 2,149.0 $ 251.9 $ (668.6) $ 4,646.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 5.3 $ 485.9 $ 148.2 $ (384.6) $ 254.8 Cash Flow Hedges: Commodity Hedges (c) — 54.0 0.6 (41.7) 12.9 Fair Value Hedges — 38.1 — — 38.1 Total Risk Management Liabilities $ 5.3 $ 578.0 $ 148.8 $ (426.3) $ 305.8 AEP Texas December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 32.7 $ — $ — $ — $ 32.7 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 30.4 $ — $ — $ — $ 30.4 Risk Management Assets Risk Management Commodity Contracts (c) — 0.6 — (0.6) — Total Assets $ 30.4 $ 0.6 $ — $ (0.6) $ 30.4 APCo December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 14.4 $ — $ — $ — $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.7 69.4 (1.0) 69.1 Total Assets $ 14.4 $ 0.7 $ 69.4 $ (1.0) $ 83.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 4.6 $ 0.3 $ (1.4) $ 3.5 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 17.6 $ — $ — $ — $ 17.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 5.8 42.0 (5.8) 42.0 Total Assets $ 17.6 $ 5.8 $ 42.0 $ (5.8) $ 59.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 7.2 $ 0.3 $ (6.7) $ 0.8 I&M December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 11.3 $ 5.3 $ (1.2) $ 15.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 11.3 — — 9.9 21.2 Fixed Income Securities: United States Government — 1,123.8 — — 1,123.8 Corporate Debt — 61.6 — — 61.6 State and Local Government — 3.3 — — 3.3 Subtotal Fixed Income Securities — 1,188.7 — — 1,188.7 Equity Securities - Domestic (b) 2,131.3 — — — 2,131.3 Total Spent Nuclear Fuel and Decommissioning Trusts 2,142.6 1,188.7 — 9.9 3,341.2 Total Assets $ 2,142.6 $ 1,200.0 $ 5.3 $ 8.7 $ 3,356.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (1.3) $ — December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 3.8 $ 7.6 $ (8.1) $ 3.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 77.7 — — 7.0 84.7 Fixed Income Securities: United States Government — 1,156.4 — — 1,156.4 Corporate Debt — 76.7 — — 76.7 State and Local Government — 7.3 — — 7.3 Subtotal Fixed Income Securities — 1,240.4 — — 1,240.4 Equity Securities - Domestic (b) 2,541.9 — — — 2,541.9 Total Spent Nuclear Fuel and Decommissioning Trusts 2,619.6 1,240.4 — 7.0 3,867.0 Total Assets $ 2,619.6 $ 1,244.2 $ 7.6 $ (1.1) $ 3,870.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 6.7 $ 8.3 $ (10.0) $ 5.0 OPCo December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ — $ — $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 40.0 $ (0.3) $ 39.7 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ — $ (0.5) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 92.5 $ — $ 92.5 PSO December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 24.0 $ 1.3 $ 25.3 Cash Flow Hedges: Interest Rate Hedges — 1.6 — (1.6) — Total Assets $ — $ 1.6 $ 24.0 $ (0.3) $ 25.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.7 $ 0.3 $ (0.4) $ 1.6 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 12.2 $ (0.4) $ 12.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 3.7 $ 0.1 $ (0.1) $ 3.7 SWEPCo December 31, 2022 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 2.2 $ 14.6 $ (0.4) $ 16.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.6 $ 0.4 $ (0.6) $ 1.4 December 31, 2021 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 11.0 $ (0.4) $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 2.1 $ 0.1 $ (0.1) $ 2.1 (a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly-traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(7) million in 2023; Level 2 matures $182 million in 2023, $134 million in periods 2024-2026, $10 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $128 million in 2023, $6 million in periods 2024-2026, $6 million in periods 2027-2028 and $(5) million in periods 2029-2033. 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, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025; $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. (h) See “Warrants Held in Investee” section of Note 10 in the 2021 Annual Report for additional information.
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2022 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2021 $ 103.1 $ 41.7 $ (0.7) $ (92.5) $ 12.1 $ 10.9 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 69.5 3.0 3.7 6.5 24.2 35.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (34.9) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 9.6 — — — — — Settlements (154.6) (44.7) (3.0) 0.3 (36.3) (45.0) Transfers into Level 3 (d) (e) 1.7 — — — — — Transfers out of Level 3 (e) 0.1 — — — — 6.9 Changes in Fair Value Allocated to Regulated Jurisdictions (f) 165.9 69.1 4.6 45.7 23.7 5.6 Balance as of December 31, 2022 $ 160.4 $ 69.1 $ 4.6 $ (40.0) $ 23.7 $ 14.2 Year Ended December 31, 2021 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 48.6 8.3 (0.1) 2.4 16.1 9.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (45.2) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 24.2 — — — — — Settlements (89.0) (28.0) (2.2) 6.3 (26.4) (15.5) Transfers into Level 3 (d) (e) (3.8) — — — — — Transfers out of Level 3 (e) (34.4) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 89.4 42.1 (0.5) 9.1 12.1 15.3 Balance as of December 31, 2021 $ 103.1 $ 41.7 $ (0.7) $ (92.5) $ 12.1 $ 10.9 Year Ended December 31, 2020 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2019 $ 109.9 $ 37.7 $ 5.8 $ (103.6) $ 15.8 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 39.5 13.2 2.5 (1.6) 11.9 2.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 35.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 13.8 — — — — — Settlements (113.1) (51.6) (8.6) 8.9 (27.6) (6.6) Transfers into Level 3 (d) (e) (3.8) — — — — — Transfers out of Level 3 (e) 5.6 0.7 0.4 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 26.1 19.3 2.0 (14.0) 10.2 4.0 Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6 (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) Included in cash flow hedges on the statements of comprehensive income. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.
Significant Unobservable Inputs for Level 3	AEP December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ 204.0 $ 167.4 Discounted Cash Flow Forward Market Price $ 2.91 $ 187.34 $ 49.14 FTRs 137.1 13.3 Discounted Cash Flow Forward Market Price (36.45) 20.72 1.18 Total $ 341.1 $ 180.7 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (c) (in millions) Energy Contracts $ 164.4 $ 135.3 Discounted Cash Flow Forward Market Price (a) $ 10.30 $ 76.70 $ 37.11 Natural Gas Contracts 3.6 — Discounted Cash Flow Forward Market Price (b) 3.11 4.02 3.47 FTRs 83.9 13.5 Discounted Cash Flow Forward Market Price (a) (23.93) 26.38 0.86 Total $ 251.9 $ 148.8 APCo December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 69.4 $ 0.3 Discounted Cash Flow Forward Market Price $ (2.82) $ 18.88 $ 3.89 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 0.3 Discounted Cash Flow Forward Market Price $ 32.20 $ 56.54 $ 44.77 FTRs 42.0 — Discounted Cash Flow Forward Market Price (0.30) 26.38 2.63 Total $ 42.0 $ 0.3 I&M December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 5.3 $ 0.7 Discounted Cash Flow Forward Market Price $ 0.16 $ 18.79 $ 1.23 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 0.2 Discounted Cash Flow Forward Market Price $ 32.20 $ 56.54 $ 44.77 FTRs 7.6 8.1 Discounted Cash Flow Forward Market Price (5.45) 17.78 (0.12) Total $ 7.6 $ 8.3 OPCo December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 40.0 Discounted Cash Flow Forward Market Price $ 2.91 $ 187.34 $ 48.76 December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) Energy Contracts $ — $ 92.5 Discounted Cash Flow Forward Market Price $ 14.26 $ 52.98 $ 30.68 PSO December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 24.0 $ 0.3 Discounted Cash Flow Forward Market Price $ (36.45) $ 3.40 $ (7.55) December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 12.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (18.39) $ 1.87 $ (2.57) SWEPCo December 31, 2022 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (c) (in millions) FTRs $ 14.6 $ 0.4 Discounted Cash Flow Forward Market Price $ (36.45) $ 3.40 $ (7.55) December 31, 2021 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (c) (in millions) Natural Gas Contracts $ 3.6 $ — Discounted Cash Flow Forward Market Price (b) $ 3.11 $ 4.02 $ 3.47 FTRs 7.4 0.1 Discounted Cash Flow Forward Market Price (a) (18.39) 1.87 (2.57) Total $ 11.0 $ 0.1 (a) Represents market prices in dollars per MWh. (b) Represents market prices in dollars per MMBtu. (c) The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.
Sensitivity of Fair Value Measurements	Uncertainty of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2022
Details of Income Taxes as Reported	Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ 113.1 $ 29.0 $ 98.0 $ (61.0) $ 43.4 $ (27.0) $ (3.3) $ (32.3) Deferred (88.8) 41.4 46.0 86.6 (51.3) 73.3 (50.5) 13.4 Total Federal 24.3 70.4 144.0 25.6 (7.9) 46.3 (53.8) (18.9) State and Local: Current 26.6 2.2 8.8 (0.4) 10.9 (0.3) — (1.8) Deferred (45.5) — 16.3 (7.0) 1.2 (1.8) 4.6 (4.5) Total State and Local (18.9) 2.2 25.1 (7.4) 12.1 (2.1) 4.6 (6.3) Income Tax Expense (Benefit) $ 5.4 $ 72.6 $ 169.1 $ 18.2 $ 4.2 $ 44.2 $ (49.2) $ (25.2) Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (27.8) $ (1.2) $ 69.8 $ 5.0 $ 26.9 $ 6.8 $ (109.6) $ (16.7) Deferred 182.6 40.5 54.1 14.9 (35.5) 25.2 105.6 26.2 Total Federal 154.8 39.3 123.9 19.9 (8.6) 32.0 (4.0) 9.5 State and Local: Current 6.0 3.0 5.8 2.2 (0.6) (3.1) — 0.4 Deferred (45.3) 0.8 14.4 — (1.4) 5.5 8.1 (10.5) Total State and Local (39.3) 3.8 20.2 2.2 (2.0) 2.4 8.1 (10.1) Income Tax Expense (Benefit) $ 115.5 $ 43.1 $ 144.1 $ 22.1 $ (10.6) $ 34.4 $ 4.1 $ (0.6) Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (138.2) $ 5.2 $ 22.2 $ 21.4 $ 11.3 $ (26.6) $ (11.4) $ (13.6) Deferred 146.9 (15.4) 65.4 (27.1) (20.6) 74.0 8.3 19.6 Total Federal 8.7 (10.2) 87.6 (5.7) (9.3) 47.4 (3.1) 6.0 State and Local: Current (16.7) (0.1) 2.8 9.3 1.9 (5.4) 0.1 (8.2) Deferred 48.5 (0.9) 16.3 0.7 (0.1) 3.2 8.2 11.6 Total State and Local 31.8 (1.0) 19.1 10.0 1.8 (2.2) 8.3 3.4 Income Tax Expense (Benefit) $ 40.5 $ (11.2) $ 106.7 $ 4.3 $ (7.5) $ 45.2 $ 5.2 $ 9.4
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	AEP Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 2,305.6 $ 2,488.1 $ 2,196.7 Less: Equity Earnings – Dolet Hills (1.4) (3.4) (2.9) Income Tax Expense 5.4 115.5 40.5 Pretax Income $ 2,309.6 $ 2,600.2 $ 2,234.3 Income Taxes on Pretax Income at Statutory Rate (21%) $ 485.0 $ 546.0 $ 469.2 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 17.1 25.9 26.5 Permanent - Miscellaneous 11.5 (1.3) (9.7) Investment Tax Credit Amortization (14.3) (22.0) (18.8) Production Tax Credits (197.1) (98.8) (83.1) State and Local Income Taxes, Net (14.0) 39.4 25.1 Removal Costs (26.5) (20.0) (18.6) AFUDC (29.3) (30.6) (32.5) Tax Adjustments (a) — (55.1) — Tax Reform Excess ADIT Reversal (214.5) (255.6) (268.2) Federal Return to Provision (17.4) (1.6) (2.6) CARES Act — — (48.0) Other 4.9 (10.8) 1.2 Income Tax Expense $ 5.4 $ 115.5 $ 40.5 Effective Income Tax Rate 0.2 % 4.4 % 1.8 % (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements. AEP Texas Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 307.9 $ 289.8 $ 241.0 Income Tax Expense (Benefit) 72.6 43.1 (11.2) Pretax Income $ 380.5 $ 332.9 $ 229.8 Income Taxes on Pretax Income at Statutory Rate (21%) $ 79.9 $ 69.9 $ 48.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: State and Local Income Taxes, Net 1.7 2.4 (0.8) AFUDC (4.1) (4.5) (4.1) Parent Company Loss Benefit — (3.2) (4.5) Tax Reform Excess ADIT Reversal (5.5) (21.3) (47.9) Other 0.6 (0.2) (2.2) Income Tax Expense (Benefit) $ 72.6 $ 43.1 $ (11.2) Effective Income Tax Rate 19.1 % 12.9 % (4.9) % AEPTCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 594.2 $ 591.7 $ 423.4 Income Tax Expense 169.1 144.1 106.7 Pretax Income $ 763.3 $ 735.8 $ 530.1 Income Taxes on Pretax Income at Statutory Rate (21%) $ 160.3 $ 154.5 $ 111.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: State and Local Income Taxes, Net 19.8 19.8 15.1 AFUDC (14.8) (14.1) (15.5) Parent Company Loss Benefit — (18.3) (7.0) Other 3.8 2.2 2.8 Income Tax Expense $ 169.1 $ 144.1 $ 106.7 Effective Income Tax Rate 22.2 % 19.6 % 20.1 % APCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 394.2 $ 348.9 $ 369.7 Income Tax Expense 18.2 22.1 4.3 Pretax Income $ 412.4 $ 371.0 $ 374.0 Income Taxes on Pretax Income at Statutory Rate (21%) $ 86.6 $ 77.9 $ 78.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 4.7 11.7 12.7 State and Local Income Taxes, Net (5.9) 2.1 7.9 Removal Costs (9.8) (7.3) (5.7) AFUDC (3.7) (4.6) (4.5) Parent Company Loss Benefit — — (6.2) Tax Adjustments (a) — 4.5 — Tax Reform Excess ADIT Reversal (50.9) (60.5) (72.3) Federal Return to Provision (2.8) (1.6) (7.2) Other — (0.1) 1.1 Income Tax Expense $ 18.2 $ 22.1 $ 4.3 Effective Income Tax Rate 4.4 % 6.0 % 1.1 % (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements. I&M Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 324.7 $ 279.8 $ 284.8 Income Tax Expense (Benefit) 4.2 (10.6) (7.5) Pretax Income $ 328.9 $ 269.2 $ 277.3 Income Taxes on Pretax Income at Statutory Rate (21%) $ 69.1 $ 56.5 $ 58.2 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 2.9 3.5 1.6 Investment Tax Credit Amortization (3.1) (6.4) (4.5) State and Local Income Taxes, Net 9.6 (1.3) 1.5 Removal Costs (12.4) (9.7) (10.5) AFUDC (2.1) (2.7) (2.4) Parent Company Loss Benefit — (2.8) (6.4) Tax Reform Excess ADIT Reversal (54.0) (46.3) (46.8) Federal Return to Provision (6.2) (0.6) 1.8 Other 0.4 (0.8) — Income Tax Expense (Benefit) $ 4.2 $ (10.6) $ (7.5) Effective Income Tax Rate 1.3 % (3.9) % (2.7) % OPCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 287.8 $ 253.6 $ 271.4 Equity Earnings of Unconsolidated Subsidiaries (0.6) — — Income Tax Expense 44.2 34.4 45.2 Pretax Income $ 331.4 $ 288.0 $ 316.6 Income Taxes on Pretax Income at Statutory Rate (21%) $ 69.6 $ 60.5 $ 66.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 3.0 2.2 3.7 State and Local Income Taxes, Net (1.6) — (1.7) AFUDC (2.9) (2.3) (2.6) Tax Adjustments (a) — 8.9 — Tax Reform Excess ADIT Reversal (27.5) (32.6) (27.2) Federal Return to Provision 3.5 (1.2) 6.5 Other 0.1 (1.1) — Income Tax Expense $ 44.2 $ 34.4 $ 45.2 Effective Income Tax Rate 13.3 % 11.9 % 14.3 % (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements. PSO Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 167.6 $ 141.1 $ 123.0 Income Tax Expense (Benefit) (49.2) 4.1 5.2 Pretax Income $ 118.4 $ 145.2 $ 128.2 Income Taxes on Pretax Income at Statutory Rate (21%) $ 24.9 $ 30.5 $ 26.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Investment Tax Credit Amortization (1.6) (1.8) (2.1) Production Tax Credits (47.7) (6.0) — State and Local Income Taxes, Net 4.3 6.4 6.5 Parent Company Loss Benefit — — (0.2) Tax Reform Excess ADIT Reversal (25.4) (25.4) (25.5) Federal Return to Provision (3.7) 0.7 (0.5) Other — (0.3) 0.1 Income Tax Expense (Benefit) $ (49.2) $ 4.1 $ 5.2 Effective Income Tax Rate (41.6) % 2.8 % 4.1 % SWEPCo Years Ended December 31, 2022 2021 2020 (in millions) Net Income $ 294.3 $ 242.1 $ 183.7 Less: Equity Earnings – Dolet Hills (1.4) (3.4) (2.9) Income Tax Expense (Benefit) (25.2) (0.6) 9.4 Pretax Income $ 267.7 $ 238.1 $ 190.2 Income Taxes on Pretax Income at Statutory Rate (21%) $ 56.2 $ 50.0 $ 39.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Reversal of Origination Flow-Through 2.3 1.8 1.9 Depletion (4.0) (2.7) (3.4) Production Tax Credits (57.1) (7.2) — State and Local Income Taxes, Net (4.9) (8.0) 2.7 Parent Company Loss Benefit — — (5.6) Tax Reform Excess ADIT Reversal (14.8) (31.1) (21.9) Other (2.9) (3.4) (4.2) Income Tax Expense (Benefit) $ (25.2) $ (0.6) $ 9.4 Effective Income Tax Rate (9.4) % (0.3) % 4.9 %
Reconciliation of Significant Temporary Differences	AEP December 31, 2022 2021 (in millions) Deferred Tax Assets $ 3,567.4 $ 3,347.1 Deferred Tax Liabilities (12,464.3) (11,991.2) Net Deferred Tax Liabilities $ (8,896.9) $ (8,644.1) Property Related Temporary Differences $ (7,788.1) $ (7,346.4) Amounts Due to Customers for Future Income Taxes 962.7 1,086.6 Deferred State Income Taxes (1,049.3) (1,211.8) Securitized Assets (98.9) (128.8) Regulatory Assets (865.2) (746.6) Accrued Nuclear Decommissioning (632.7) (743.2) Net Operating Loss Carryforward 132.4 303.2 Tax Credit Carryforward 612.0 440.1 Operating Lease Liability 142.9 116.3 Investment in Partnership (338.9) (392.1) Valuation Allowance (28.2) (25.0) Deferred Revenues 7.1 8.8 Postretirement Benefits 2.5 (46.2) All Other, Net 44.8 41.0 Net Deferred Tax Liabilities $ (8,896.9) $ (8,644.1) AEP Texas December 31, 2022 2021 (in millions) Deferred Tax Assets $ 177.0 $ 173.8 Deferred Tax Liabilities (1,321.2) (1,262.7) Net Deferred Tax Liabilities $ (1,144.2) $ (1,088.9) Property Related Temporary Differences $ (1,130.7) $ (1,060.2) Amounts Due to Customers for Future Income Taxes 111.0 110.0 Deferred State Income Taxes (36.6) (32.2) Securitized Transition Assets (65.0) (84.4) Regulatory Assets (48.9) (45.1) Operating Lease Liability 20.3 15.8 All Other, Net 5.7 7.2 Net Deferred Tax Liabilities $ (1,144.2) $ (1,088.9) AEPTCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 165.0 $ 161.2 Deferred Tax Liabilities (1,221.5) (1,139.5) Net Deferred Tax Liabilities $ (1,056.5) $ (978.3) Property Related Temporary Differences $ (1,081.5) $ (1,012.4) Amounts Due to Customers for Future Income Taxes 118.5 120.1 Deferred State Income Taxes (108.1) (97.0) Regulatory Assets (1.1) (1.3) Net Operating Loss Carryforward 5.5 8.1 Tax Credit Carryforward 0.2 0.1 Operating Lease Liability 0.3 0.1 Valuation Allowance (0.1) (0.1) All Other, Net 9.8 4.1 Net Deferred Tax Liabilities $ (1,056.5) $ (978.3) APCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 510.3 $ 495.1 Deferred Tax Liabilities (2,502.5) (2,299.8) Net Deferred Tax Liabilities $ (1,992.2) $ (1,804.7) Property Related Temporary Differences $ (1,509.8) $ (1,476.5) Amounts Due to Customers for Future Income Taxes 163.0 182.1 Deferred State Income Taxes (318.5) (288.8) Securitized Assets (33.9) (39.3) Regulatory Assets (301.2) (177.0) Operating Lease Liability 15.6 14.2 All Other, Net (7.4) (19.4) Net Deferred Tax Liabilities $ (1,992.2) $ (1,804.7) I&M December 31, 2022 2021 (in millions) Deferred Tax Assets $ 933.7 $ 1,072.2 Deferred Tax Liabilities (2,090.7) (2,172.4) Net Deferred Tax Liabilities $ (1,157.0) $ (1,100.2) Property Related Temporary Differences $ (398.0) $ (286.2) Amounts Due to Customers for Future Income Taxes 114.3 135.5 Deferred State Income Taxes (227.0) (222.0) Regulatory Assets (29.5) (23.6) Accrued Nuclear Decommissioning (632.7) (743.2) Operating Lease Liability 13.6 13.5 All Other, Net 2.3 25.8 Net Deferred Tax Liabilities $ (1,157.0) $ (1,100.2) OPCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 218.8 $ 204.4 Deferred Tax Liabilities (1,319.9) (1,205.3) Net Deferred Tax Liabilities $ (1,101.1) $ (1,000.9) Property Related Temporary Differences $ (1,133.8) $ (1,042.0) Amounts Due to Customers for Future Income Taxes 112.6 117.7 Deferred State Income Taxes (59.6) (58.8) Regulatory Assets (57.6) (39.8) Operating Lease Liability 15.5 17.2 All Other, Net 21.8 4.8 Net Deferred Tax Liabilities $ (1,101.1) $ (1,000.9) PSO December 31, 2022 2021 (in millions) Deferred Tax Assets $ 225.0 $ 170.0 Deferred Tax Liabilities (1,013.6) (952.3) Net Deferred Tax Liabilities $ (788.6) $ (782.3) Property Related Temporary Differences $ (763.3) $ (708.6) Amounts Due to Customers for Future Income Taxes 96.0 111.5 Deferred State Income Taxes (81.9) (83.2) Regulatory Assets (140.2) (228.0) Net Operating Loss Carryforward 25.8 111.4 Tax Credit Carryforward 54.3 6.6 All Other, Net 20.7 8.0 Net Deferred Tax Liabilities $ (788.6) $ (782.3) SWEPCo December 31, 2022 2021 (in millions) Deferred Tax Assets $ 374.9 $ 336.4 Deferred Tax Liabilities (1,464.6) (1,424.0) Net Deferred Tax Liabilities $ (1,089.7) $ (1,087.6) Property Related Temporary Differences $ (1,053.8) $ (989.6) Amounts Due to Customers for Future Income Taxes 146.2 154.8 Deferred State Income Taxes (208.7) (234.9) Regulatory Assets (114.1) (101.4) Net Operating Loss Carryforward 42.7 67.4 Tax Credit Carryforward 66.0 8.5 All Other, Net 32.0 7.6 Net Deferred Tax Liabilities $ (1,089.7) $ (1,087.6)
State Net Income Tax Operating Loss Carryforwards	State Net Income Tax Operating Loss Years of Company State/Municipality Carryforward Expiration (in millions) AEP Arkansas $ 224.4 2023 - 2032 AEP Colorado 82.6 NA AEP Illinois 52.4 2031 - 2041 AEP Kentucky 231.3 2030 - 2037 AEP Louisiana 586.8 NA AEP Michigan 58.7 2029 - 2031 AEP New Jersey 13.7 2036 - 2040 AEP New Mexico 22.9 NA AEP Ohio Municipal 1,257.7 2023 - 2027 AEP Oklahoma 943.3 2037 - 2037 AEP Pennsylvania 64.4 2030 - 2042 AEP Tennessee 77.7 2030 - 2037 AEP Virginia 11.2 2030 - 2037 AEP West Virginia 12.3 2029 - 2037 AEPTCo Oklahoma 33.0 2037 - 2037 OPCo Ohio Municipal 190.1 2024 - 2027 PSO Oklahoma 899.6 2037 - 2037 SWEPCo Arkansas 224.2 2023 - 2032 SWEPCo Louisiana 577.2 NA
Summary of Tax Credit Carryforwards	Total Federal Total State Tax Credit Tax Credit Company Carryforward Carryforward (in millions) AEP $ 612.0 $ 39.2 AEP Texas 1.5 — AEPTCo 0.2 — APCo 2.0 — I&M 11.4 — OPCo 1.0 — PSO 54.3 39.2 SWEPCo 66.0 —
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP 2022 2021 2020 (in millions) Balance as of January 1, $ 14.3 $ 13.2 $ 24.1 Increase – Tax Positions Taken During a Prior Period 5.1 1.2 0.6 Decrease – Tax Positions Taken During a Prior Period — (3.2) (14.5) Increase – Tax Positions Taken During the Current Year 3.8 3.1 3.0 Decrease – Tax Positions Taken During the Current Year — — — Decrease – Settlements with Taxing Authorities — — — Decrease – Lapse of the Applicable Statute of Limitations — — — Balance as of December 31, $ 23.2 $ 14.3 $ 13.2 OPCo 2022 2021 2020 (in millions) Balance as of January 1, $ — $ 3.2 $ 8.4 Increase – Tax Positions Taken During a Prior Period 5.1 — — Decrease – Tax Positions Taken During a Prior Period — (3.2) (5.2) Increase – Tax Positions Taken During the Current Year — — — Decrease – Tax Positions Taken During the Current Year — — — Decrease – Settlements with Taxing Authorities — — — Decrease – Lapse of the Applicable Statute of Limitations — — — Balance as of December 31, $ 5.1 $ — $ 3.2

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2022
Lease Rental Costs	Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 157.5 $ 18.4 $ 1.1 $ 17.9 $ 29.5 $ 16.9 $ 11.8 $ 15.3 Finance Lease Cost: Amortization of Right-of-Use Assets 205.5 6.8 — 7.9 78.7 4.9 3.2 10.8 Interest on Lease Liabilities 13.4 1.3 — 2.0 3.1 0.8 0.6 2.1 Total Lease Rental Costs (a) $ 376.4 $ 26.5 $ 1.1 $ 27.8 $ 111.3 $ 22.6 $ 15.6 $ 28.2 Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 275.3 $ 18.4 $ 1.7 $ 19.3 $ 90.2 $ 19.0 $ 8.7 $ 12.1 Finance Lease Cost: Amortization of Right-of-Use Assets 74.7 6.7 — 7.7 12.9 4.9 3.2 11.0 Interest on Lease Liabilities 14.4 1.4 — 2.4 3.0 0.8 0.6 2.5 Total Lease Rental Costs (a) $ 364.4 $ 26.5 $ 1.7 $ 29.4 $ 106.1 $ 24.7 $ 12.5 $ 25.6 Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Operating Lease Cost $ 279.6 $ 17.4 $ 2.6 $ 19.1 $ 101.5 $ 17.1 $ 7.8 $ 9.4 Finance Lease Cost: Amortization of Right-of-Use Assets 61.9 6.3 — 7.4 6.5 4.7 3.5 10.9 Interest on Lease Liabilities 15.4 1.5 — 2.7 3.1 0.9 0.7 2.2 Total Lease Rental Costs (a) $ 356.9 $ 25.2 $ 2.6 $ 29.2 $ 111.1 $ 22.7 $ 12.0 $ 22.5 (a) Excludes variable and short-term lease costs, which were immaterial.
Supplemental Balance Sheet Information Related to Leases	December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo Weighted-Average Remaining Lease Term (years): Operating Leases 12.69 4.33 2.05 5.29 5.79 5.98 23.90 23.55 Finance Leases 4.61 5.39 0.00 4.25 4.76 5.27 6.02 4.13 Weighted-Average Discount Rate: Operating Leases 3.54 % 4.15 % 1.96 % 3.61 % 3.62 % 3.73 % 3.43 % 3.41 % Finance Leases 5.76 % 4.75 % — % 7.09 % 8.99 % 4.53 % 4.63 % 4.80 % December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo Weighted-Average Remaining Lease Term (years): Operating Leases 10.39 5.91 2.95 5.68 5.87 6.69 20.89 20.24 Finance Leases 2.95 5.51 0.00 4.97 2.10 5.54 6.18 4.53 Weighted-Average Discount Rate: Operating Leases 3.35 % 3.53 % 0.90 % 3.42 % 3.46 % 3.56 % 3.35 % 3.34 % Finance Leases 3.26 % 4.31 % — % 7.16 % 3.02 % 4.19 % 4.23 % 4.68 % Year Ended December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows Used for Operating Leases $ 155.1 $ 18.3 $ 1.0 $ 17.9 $ 29.7 $ 17.5 $ 10.5 $ 13.7 Operating Cash Flows Used for Finance Leases 13.6 1.3 — 2.0 3.2 0.8 0.6 2.1 Financing Cash Flows Used for Finance Leases 309.5 6.8 — 7.9 130.7 4.9 3.2 10.8 Non-cash Acquisitions Under Operating Leases $ 191.4 $ 36.7 $ 1.7 $ 23.1 $ 19.1 $ 8.4 $ 46.0 $ 53.6 Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows Used for Operating Leases $ 279.9 $ 18.0 $ 1.6 $ 19.3 $ 92.9 $ 19.0 $ 8.7 $ 11.6 Operating Cash Flows Used for Finance Leases 14.3 1.4 — 2.4 2.9 0.8 0.6 2.5 Financing Cash Flows Used for Finance Leases 64.0 6.7 — 7.7 6.8 4.9 3.2 10.9 Non-cash Acquisitions Under Operating Leases $ 117.0 $ 4.4 $ 2.1 $ 4.2 $ 2.6 $ 4.2 $ 33.4 $ 42.9
Property, Plant and Equipment and Related Obligations Under Finance Leases	December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Property, Plant and Equipment Under Finance Leases: Generation $ 120.9 $ — $ — $ 41.1 $ 28.0 $ — $ 0.6 $ 25.9 Other Property, Plant and Equipment 321.4 53.7 — 20.1 40.6 32.7 25.2 58.3 Total Property, Plant and Equipment 442.3 53.7 — 61.2 68.6 32.7 25.8 84.2 Accumulated Amortization 229.6 23.6 — 31.9 34.8 13.8 10.8 54.6 Net Property, Plant and Equipment Under Finance Leases $ 212.7 $ 30.1 $ — $ 29.3 $ 33.8 $ 18.9 $ 15.0 $ 29.6 Obligations Under Finance Leases: Noncurrent Liability $ 168.4 $ 23.1 $ — $ 21.6 $ 27.1 $ 14.2 $ 11.7 $ 31.3 Liability Due Within One Year 57.3 7.0 — 7.7 6.9 4.7 3.3 10.9 Total Obligations Under Finance Leases $ 225.7 $ 30.1 $ — $ 29.3 $ 34.0 $ 18.9 $ 15.0 $ 42.2 December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Property, Plant and Equipment Under Finance Leases: Generation $ 389.9 $ — $ — $ 42.8 $ 156.8 $ — $ 0.6 $ 34.3 Other Property, Plant and Equipment 328.1 50.7 — 20.4 42.1 32.1 23.9 55.7 Total Property, Plant and Equipment 718.0 50.7 — 63.2 198.9 32.1 24.5 90.0 Accumulated Amortization 225.0 19.9 — 27.5 38.2 12.8 9.2 47.8 Net Property, Plant and Equipment Under Finance Leases $ 493.0 $ 30.8 $ — $ 35.7 $ 160.7 $ 19.3 $ 15.3 $ 42.2 Obligations Under Finance Leases: Noncurrent Liability $ 198.2 $ 24.2 $ — $ 28.1 $ 31.7 $ 14.9 $ 12.3 $ 38.9 Liability Due Within One Year 305.3 6.6 — 7.6 130.5 4.4 3.0 10.8 Total Obligations Under Finance Leases $ 503.5 $ 30.8 $ — $ 35.7 $ 162.2 $ 19.3 $ 15.3 $ 49.7
Operating Lease Assets and Related Obligations	December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Operating Lease Assets $ 645.5 $ 94.7 $ 2.7 $ 73.6 $ 64.3 $ 73.8 $ 106.1 $ 123.4 Obligations Under Operating Leases: Noncurrent Liability $ 552.5 $ 67.8 $ 1.5 $ 59.1 $ 48.9 $ 60.3 $ 99.3 $ 120.2 Liability Due Within One Year 113.6 28.6 1.3 15.0 16.0 13.5 8.9 8.4 Total Obligations Under Operating Leases $ 666.1 $ 96.4 $ 2.8 $ 74.1 $ 64.9 $ 73.8 $ 108.2 $ 128.6 December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Operating Lease Assets $ 589.0 $ 73.6 $ 2.0 $ 66.9 $ 63.5 $ 81.2 $ 68.9 $ 80.1 Obligations Under Operating Leases: Noncurrent Liability $ 501.4 $ 61.3 $ 1.3 $ 52.4 $ 48.9 $ 68.6 $ 62.2 $ 77.7 Liability Due Within One Year 99.8 14.0 0.9 15.1 15.5 13.1 6.9 8.1 Total Obligations Under Operating Leases $ 601.2 $ 75.3 $ 2.2 $ 67.5 $ 64.4 $ 81.7 $ 69.1 $ 85.8
Finance Lease Liabilities Rolling Future Minimum Lease Payments	Finance Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) 2023 $ 67.9 $ 8.3 $ — $ 9.6 $ 9.2 $ 5.4 $ 3.8 $ 12.4 2024 71.5 7.2 — 8.8 12.1 4.6 3.3 16.5 2025 41.0 5.5 — 7.5 6.3 3.2 2.5 6.1 2026 25.0 4.4 — 2.9 3.9 2.6 2.2 2.8 2027 19.3 3.5 — 1.8 3.4 2.1 1.8 2.4 After 2027 32.6 5.5 — 2.8 7.6 3.4 3.7 5.6 Total Future Minimum Lease Payments 257.3 34.4 — 33.4 42.5 21.3 17.3 45.8 Less: Imputed Interest 31.6 4.3 — 4.1 8.5 2.4 2.3 3.6 Estimated Present Value of Future Minimum Lease Payments $ 225.7 $ 30.1 $ — $ 29.3 $ 34.0 $ 18.9 $ 15.0 $ 42.2
Operating Lease Liabilities Rolling Future Minimum Lease Payments	Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) 2023 $ 138.7 $ 32.3 $ 1.4 $ 17.5 $ 18.8 $ 16.4 $ 11.5 $ 14.4 2024 125.9 29.7 0.9 14.6 17.7 14.9 10.7 12.7 2025 86.7 13.1 0.4 11.8 9.2 13.2 9.5 11.4 2026 75.5 10.9 0.2 10.3 8.3 12.0 8.6 10.2 2027 65.6 8.3 — 9.1 7.5 10.7 7.8 8.8 After 2027 352.2 11.7 — 19.2 9.8 15.7 116.4 141.8 Total Future Minimum Lease Payments 844.6 106.0 2.9 82.5 71.3 82.9 164.5 199.3 Less: Imputed Interest 178.5 9.6 0.1 8.4 6.4 9.1 56.3 70.7 Estimated Present Value of Future Minimum Lease Payments $ 666.1 $ 96.4 $ 2.8 $ 74.1 $ 64.9 $ 73.8 $ 108.2 $ 128.6
Maximum Potential Loss	Company Maximum (in millions) AEP $ 46.0 AEP Texas 11.1 APCo 6.1 I&M 4.4 OPCo 7.6 PSO 4.8 SWEPCo 5.3

Financing Activities (Tables)

Financing Activities (Tables)	12 Months Ended
Financing Activities (Tables)	Dec. 31, 2022
AEP Common Stock	Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2019 514,373,631 20,204,160 Issued 2,434,723 — Balance, December 31, 2020 516,808,354 20,204,160 Issued 7,607,821 — Balance, December 31, 2021 524,416,175 20,204,160 Issued 683,146 — Treasury Stock Reissued — (8,970,920) (a) Balance, December 31, 2022 525,099,321 11,233,240 (a) Reissued Treasury Stock used to fulfill share commitments related to AEP’s Equity Units. See “Equity Units” section below for additional information.
Long-term Debt	Weighted-Average Interest Rate Ranges as of Outstanding as of Interest Rate as of December 31, December 31, Company Maturity December 31, 2022 2022 2021 2022 2021 (in millions) AEP (as adjusted) Senior Unsecured Notes 2022-2052 3.98% 0.75%-8.13% 0.61%-8.13% $ 30,174.8 $ 28,185.7 Pollution Control Bonds (a) 2022-2036 (b) 2.74% 0.63%-4.55% 0.19%-4.55% 1,770.2 1,869.3 Notes Payable – Nonaffiliated (c) 2022-2032 4.29% 0.93%-6.37% 0.79%-6.37% 269.7 211.3 Securitization Bonds 2023-2029 (d) 2.91% 2.01%-3.77% 2.01%-3.77% 487.8 603.5 Spent Nuclear Fuel Obligation (e) 285.6 281.3 Junior Subordinated Notes (f) 2024-2027 2.35% 1.30%-3.88% 1.30%-3.88% 2,381.3 2,373.0 Other Long-term Debt 2022-2059 5.44% 1.15%-13.72% 0.76%-13.72% 1,431.6 1,033.5 Total Long-term Debt Outstanding $ 36,801.0 $ 34,557.6 AEP Texas Senior Unsecured Notes 2023-2052 4.06% 2.10%-6.76% 2.10%-6.76% $ 4,702.7 $ 4,135.5 Pollution Control Bonds 2023-2030 (b) 3.42% 0.90%-4.55% 0.90%-4.55% 440.2 439.9 Securitization Bonds 2024-2029 (d) 2.50% 2.06%-2.84% 2.06%-2.84% 314.4 404.7 Other Long-term Debt 2025-2059 5.67% 4.50%-5.67% 1.35%-4.50% 200.5 200.7 Total Long-term Debt Outstanding $ 5,657.8 $ 5,180.8 AEPTCo Senior Unsecured Notes 2023-2052 3.83% 2.75%-5.52% 2.75%-5.52% $ 4,782.8 $ 4,343.9 Total Long-term Debt Outstanding $ 4,782.8 $ 4,343.9 APCo Senior Unsecured Notes 2025-2050 4.68% 2.70%-7.00% 2.70%-7.00% $ 4,581.4 $ 4,083.7 Pollution Control Bonds (a) 2024-2036 (b) 2.74% 0.63%-3.80% 0.19%-2.75% 429.4 529.5 Securitization Bonds 2023-2028 (d) 3.67% 2.01%-3.77% 2.01%-3.77% 173.3 198.8 Other Long-term Debt 2023-2026 5.34% 4.84%-13.72% 1.24%-13.72% 226.4 126.9 Total Long-term Debt Outstanding $ 5,410.5 $ 4,938.9 I&M Senior Unsecured Notes 2023-2051 4.19% 3.20%-6.05% 3.20%-6.05% $ 2,597.3 $ 2,595.5 Pollution Control Bonds (a) 2025 (b) 2.49% 0.75%-3.05% 0.75%-3.05% 189.0 188.7 Notes Payable – Nonaffiliated (c) 2023-2027 4.26% 0.93%-5.93% 0.79%-1.24% 183.8 122.2 Spent Nuclear Fuel Obligation (e) 285.6 281.3 Other Long-term Debt 2025 6.00% 6.00% 6.00% 5.1 7.3 Total Long-term Debt Outstanding $ 3,260.8 $ 3,195.0 OPCo Senior Unsecured Notes 2030-2051 3.87% 1.63%-6.60% 1.63%-6.60% $ 2,969.7 $ 2,967.8 Other Long-term Debt 2028 1.15% 1.15% 1.15% 0.6 0.7 Total Long-term Debt Outstanding $ 2,970.3 $ 2,968.5 PSO Senior Unsecured Notes 2025-2051 3.74% 2.20%-6.63% 2.20%-6.63% $ 1,785.6 $ 1,785.5 Other Long-term Debt 2025-2027 5.69% 3.00%-5.75% 1.47%-3.00% 127.2 128.0 Total Long-term Debt Outstanding $ 1,912.8 $ 1,913.5 SWEPCo Senior Unsecured Notes 2026-2051 3.57% 1.65%-6.20% 1.65%-6.20% $ 3,297.6 $ 3,295.1 Notes Payable – Nonaffiliated (c) 2024-2032 5.38% 4.58%-6.37% 4.58%-6.37% 55.9 59.1 Other Long-term Debt 2028 4.68% 4.68% 4.68% 38.1 41.0 Total Long-term Debt Outstanding $ 3,391.6 $ 3,395.2 (a) For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (b) Certain Pollution Control Bonds are subject to redemption earlier than the maturity date. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date. (e) Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information. (f) See “Equity Units” section below for additional information.
Long-term Debt 5-Year Maturity	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) 2023 $ 2,486.4 $ 278.5 $ 60.0 $ 251.8 $ 341.8 $ 0.1 $ 0.5 $ 6.2 2024 1,590.2 (a) 96.0 95.0 113.5 56.4 0.1 0.6 6.2 2025 3,253.9 (b) 524.5 90.0 673.3 220.5 0.1 250.6 6.2 2026 1,754.0 75.0 425.0 30.9 8.5 0.1 50.6 906.2 2027 2,251.9 25.6 — 355.6 1.7 0.1 0.3 6.2 After 2027 25,773.8 4,706.4 4,166.0 4,031.8 2,660.6 3,000.1 1,625.0 2,488.2 Principal Amount 37,110.2 5,706.0 4,836.0 5,456.9 3,289.5 3,000.6 1,927.6 3,419.2 Unamortized Discount, Net and Debt Issuance Costs (309.2) (48.2) (53.2) (46.4) (28.7) (30.3) (14.8) (27.6) Total Long-term Debt Outstanding $ 36,801.0 $ 5,657.8 $ 4,782.8 $ 5,410.5 $ 3,260.8 $ 2,970.3 $ 1,912.8 $ 3,391.6 (a) Amount includes $805 million of Junior Subordinated Notes. See “Equity Units” section below for additional information. (b) Amount includes $850 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.
Dividend Payment Restrictions	AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Restricted Retained Earnings $ 3,023.0 (a) $ 1,105.7 $ — $ 543.1 $ 688.2 $ — $ — $ 373.0 (a) Includes the restrictions of consolidated and non-consolidated subsidiaries.
Lines of Credit and Short-term Debt	December 31, 2022 2021 Company Type of Debt Outstanding Interest Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 4.67 % $ 750.0 0.19 % AEP Commercial Paper 2,862.2 4.80 % 1,364.0 0.34 % AEP Term Loan — — % 500.0 0.81 % AEP Term Loan 125.0 5.17 % — — % AEP Term Loan 150.0 5.17 % — — % AEP Term Loan 100.0 5.23 % — — % AEP Term Loan 125.0 4.87 % — — % Total Short-term Debt $ 4,112.2 $ 2,614.0 (a) Weighted-average rate as of December 31, 2022 and 2021, respectively. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2022: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2022 Limit (in millions) (as adjusted) AEP Texas $ 348.8 $ 652.3 $ 173.3 $ 247.8 $ (96.5) $ 500.0 AEPTCo 480.2 137.0 189.4 28.9 (195.5) 820.0 (a) APCo 438.4 214.2 181.7 45.4 (162.4) 500.0 I&M 318.6 23.0 105.2 22.3 (226.9) 500.0 OPCo 262.5 246.1 101.3 86.9 (172.9) 500.0 PSO 364.2 432.5 224.5 402.8 (364.2) 400.0 SWEPCo 358.4 156.6 219.3 109.7 (310.7) 400.0 Year Ended December 31, 2021: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2021 Limit (in millions) AEP Texas $ 355.5 $ 104.7 $ 172.5 $ 40.0 $ (26.9) $ 500.0 AEPTCo 444.9 117.3 189.1 29.7 (108.8) 820.0 (a) APCo 199.3 616.9 87.5 118.3 (178.5) 500.0 I&M 166.5 368.2 110.4 67.7 (71.8) 500.0 OPCo 259.2 622.9 61.6 127.2 42.0 500.0 PSO 267.7 747.3 134.0 113.1 (72.3) 400.0 SWEPCo 280.3 561.9 142.4 287.4 153.8 400.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Nonutility Money Pool Activity	Year Ended December 31, 2022: Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2022 (in millions) AEP Texas $ 7.0 $ 6.8 $ 6.9 SWEPCo 2.1 2.1 2.1 Year Ended December 31, 2021: Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool December 31, 2021 (in millions) AEP Texas $ 7.1 $ 6.9 $ 6.9 SWEPCo 2.1 2.1 2.1
Direct Borrowing Activity	Year Ended December 31, 2022: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2022 December 31, 2022 Borrowing Limit (in millions) $ 52.4 $ 141.8 $ 6.7 $ 57.5 $ 29.4 $ — $ 50.0 (a) Year Ended December 31, 2021: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP December 31, 2021 December 31, 2021 Borrowing Limit (in millions) $ 14.6 $ 224.2 $ 1.8 $ 118.0 $ 1.5 $ 12.7 $ 50.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2022 2021 2020 Maximum Interest Rate 5.28 % 0.48 % 2.70 % Minimum Interest Rate 0.10 % 0.02 % 0.27 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed Average Interest Rate for Funds Loaned Company 2022 2021 2020 2022 2021 2020 AEP Texas 1.08 % 0.33 % 1.51 % 1.99 % 0.26 % 0.81 % AEPTCo 1.81 % 0.32 % 1.29 % 2.47 % 0.10 % 1.99 % APCo 2.34 % 0.41 % 2.12 % 2.39 % 0.25 % 0.85 % I&M 2.57 % 0.33 % 1.07 % 2.20 % 0.23 % 1.18 % OPCo 3.51 % 0.27 % 0.99 % 1.22 % 0.14 % 2.06 % PSO 2.65 % 0.34 % 0.92 % 0.75 % 0.07 % 1.95 % SWEPCo 2.80 % 0.26 % 1.27 % 0.55 % 0.18 % — %
Maximum, Minimum and Average Interest Rates for Funds Borrowed from and Loaned to the Nonutility Money Pool	Maximum Interest Rate Minimum Interest Rate Average Interest Rate Year Ended for Funds Loaned to for Funds Loaned to for Funds Loaned to December 31, Company the Nonutility Money Pool the Nonutility Money Pool the Nonutility Money Pool 2022 AEP Texas 5.28 % 0.46 % 2.23 % 2022 SWEPCo 5.28 % 0.46 % 2.23 % 2021 AEP Texas 0.58 % 0.21 % 0.37 % 2021 SWEPCo 0.58 % 0.21 % 0.37 % 2020 AEP Texas 2.70 % 0.27 % 1.18 % 2020 SWEPCo 2.70 % 0.27 % 1.18 %
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 for Funds for Funds for Funds for Funds for Funds for Funds Year Ended Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to December 31, AEP AEP AEP AEP AEP AEP 2022 5.28 % 0.46 % 5.28 % 0.46 % 2.08 % 2.07 % 2021 0.86 % 0.25 % 0.86 % 0.25 % 0.38 % 0.35 % 2020 2.70 % 0.27 % 2.70 % 0.27 % 1.20 % 1.13 %
Customer Accounts Receivable Managed Portfolio	December 31, 2022 2021 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,167.7 $ 995.2 Short-term – Securitized Debt of Receivables 750.0 750.0 Delinquent Securitized Accounts Receivable 44.2 57.9 Bad Debt Reserves Related to Securitization 39.7 42.8 Unbilled Receivables Related to Securitization 360.9 307.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2022 2021 (in millions) APCo $ 194.4 $ 153.1 I&M 166.9 156.9 OPCo 478.6 392.7 PSO 155.5 114.5 SWEPCo 194.0 153.0
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2022 2021 (a) 2020 (in millions) APCo $ 9.4 $ 4.9 $ 5.2 I&M 9.7 7.0 7.9 OPCo 29.8 8.3 24.1 PSO 7.4 3.4 4.8 SWEPCo 9.4 5.4 6.7
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2022 2021 2020 (in millions) APCo $ 1,552.9 $ 1,324.1 $ 1,272.9 I&M 2,045.6 1,927.0 1,891.8 OPCo 3,101.3 2,458.5 2,366.2 PSO 1,809.5 1,406.4 1,221.0 SWEPCo 1,858.4 1,636.1 1,593.8
Interest Expense Incurred For Funds Borrowed from Utility Money Pool	Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 0.9 $ 0.3 $ 0.8 AEPTCo 3.5 0.6 1.5 APCo 5.6 0.1 2.8 I&M 2.9 0.2 1.4 OPCo 2.3 0.1 1.8 PSO 5.5 0.3 0.6 SWEPCo 4.9 0.3 1.5
Interest Income Earned for Funds Loaned to Utility Money Pool	Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 2.6 $ 0.1 $ 0.7 AEPTCo 1.6 0.4 2.4 APCo 2.8 0.3 0.7 I&M 0.5 0.2 0.2 OPCo 0.4 0.1 — PSO 0.3 — 0.1 SWEPCo 0.2 0.1 —
Comparative Accounts Receivable Information	Years Ended December 31, 2022 2021 2020 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.84 % 0.19 % 0.85 % Net Uncollectible Accounts Receivable Written Off $ 29.5 $ 26.5 $ 15.3

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
Stock-Based Compensation (Tables)	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Units and Reinvested Dividends on Outstanding Performance Units	Years Ended December 31, Performance Shares 2022 2021 2020 Awarded Shares (in thousands) 530.3 565.0 424.8 Weighted-Average Share Fair Value at Grant Date $ 97.61 $ 81.02 $ 116.56 Vesting Period (in years) 3 3 3 Performance Shares and AEP Career Shares Years Ended December 31, 2022 2021 2020 Awarded Shares (in thousands) 63.3 74.5 73.4 Weighted-Average Fair Value at Grant Date $ 98.73 $ 84.48 $ 84.87 Vesting Period (in years) (a) (a) (a)
Summary of Performance Scores and Performance Units Earned	Years Ended December 31, Performance Shares 2022 2021 2020 Certified Performance Score 131.1 % 102.9 % 128.2 % Performance Shares Earned 512,660 537,166 757,858 Performance Shares Mandatorily Deferred as AEP Career Shares 28,282 14,613 13,614 Performance Shares Voluntarily Deferred into the Incentive Compensation Deferral Program 23,609 22,915 26,936 Performance Shares to be Settled (a) 460,769 499,638 717,308 (a) Performance shares settled in AEP common stock in the quarter following the end of the year shown.
Summary of Cash Payouts for Performance Units and Career Shares	Years Ended December 31, Performance Shares and AEP Career Shares 2022 2021 2020 (in millions) AEP Common Stock Settlements for Performance Shares $ 43.2 $ 54.7 $ 75.4 AEP Common Stock Settlements for Career Share Distributions 5.1 4.0 1.9
Status of Nonvested Performance Units	Nonvested Performance Shares Shares Weighted (in thousands) Nonvested as of January 1, 2022 923.8 $ 96.15 Awarded 530.3 97.61 Dividends 45.5 98.73 Vested (a) (395.8) 116.06 Forfeited (91.6) 84.81 Nonvested as of December 31, 2022 1,012.2 90.27 (a) The vested Performance Shares will be converted to 461 thousand shares based on the closing share price on the day before settlement.
Monte Carlo Valuation Assumptions	Years Ended December 31, Assumptions 2022 2021 2020 Valuation Period (in years) (a) 2.86 2.88 2.87 Expected Volatility Minimum 25.92 % 25.87 % 13.67 % Expected Volatility Maximum 40.82 % 39.90 % 28.15 % Expected Volatility Average 31.09 % 31.01 % 16.39 % Dividend Rate (b) — % — % — % Risk Free Rate 1.64 % 0.19 % 1.40 % (a) Period from award date to vesting date. (b) Equivalent to reinvesting dividends.
Summary of Units Awarded and Fair Value of Restricted Stock Units	Years Ended December 31, Restricted Stock Units 2022 2021 2020 Awarded Units (in thousands) 290.4 280.0 268.7 Weighted-Average Grant Date Fair Value $ 90.48 $ 80.39 $ 94.38
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	Years Ended December 31, Restricted Stock Units 2022 2021 2020 (in millions) Fair Value of Restricted Stock Units Vested $ 17.8 $ 20.5 $ 22.9 Intrinsic Value of Restricted Stock Units Vested (a) 20.3 22.0 25.2 (a) Intrinsic value is calculated as market price at the vesting date.
Status of Nonvested Restricted Shares and Restricted Stock Units	Nonvested Restricted Stock Units Shares/Units Weighted (in thousands) Nonvested as of January 1, 2022 424.3 $ 84.86 Awarded 290.4 90.48 Vested (209.0) 85.15 Forfeited (46.1) 85.80 Nonvested as of December 31, 2022 459.6 88.05
Stock Unit Accumulation Plan for Non-employee Directors	Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2022 2021 2020 Awarded Units (in thousands) 14.5 12.6 12.1 Weighted-Average Grant Date Fair Value $ 95.16 $ 84.54 $ 83.80
Compensation Cost and Actual Tax Benefit Realized for Tax Deductions from Compensation Cost for Share-based Payment Arrangements	Years Ended December 31, Share-based Compensation Plans 2022 2021 2020 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 63.3 $ 61.1 $ 53.8 Actual Tax Benefit 8.0 8.7 7.2 Total Compensation Cost Capitalized 16.0 16.9 20.4 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2022
Affiliated Revenues	Related Party Revenues AEP Texas AEPTCo APCo I&M (a) OPCo PSO SWEPCo (in millions) Year Ended December 31, 2022 Direct Sales to East Affiliates $ — $ — $ 169.7 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — — — 1.3 Transmission Revenues — 1,276.4 77.5 7.7 (3.6) — 51.5 Other Revenues 3.5 7.4 8.9 7.6 22.4 2.9 1.1 Total Affiliated Revenues $ 3.5 $ 1,283.8 $ 256.1 $ 15.3 $ 18.8 $ 2.9 $ 53.9 Related Party Revenues AEP Texas AEPTCo APCo I&M (a) OPCo PSO SWEPCo (in millions) Year Ended December 31, 2021 Direct Sales to East Affiliates $ — $ — $ 128.6 $ — $ — $ — $ — Transmission Revenues — 1,136.1 60.3 (2.5) (1.1) — 39.6 Other Revenues 3.9 17.8 9.0 6.3 25.9 4.2 1.4 Total Affiliated Revenues $ 3.9 $ 1,153.9 $ 197.9 $ 3.8 $ 24.8 $ 4.2 $ 41.0 Related Party Revenues AEP Texas AEPTCo APCo I&M (a) OPCo PSO SWEPCo (in millions) Year Ended December 31, 2020 Direct Sales to East Affiliates $ — $ — $ 112.5 $ — $ — $ — $ — Auction Sales to OPCo (b) — — 5.3 3.1 — — — Direct Sales to AEPEP 87.5 — — — — — — Transmission Revenues — 885.0 49.1 2.9 16.6 — 37.4 Other Revenues 3.3 11.3 7.8 4.5 24.9 5.2 1.6 Total Affiliated Revenues $ 90.8 $ 896.3 $ 174.7 $ 10.5 $ 41.5 $ 5.2 $ 39.0 (a) I&M’s affiliated revenues exclude capacity sales to KPCo from Rockport Plant, Unit 2 and barging, urea transloading and other transportation services to affiliates. See sections “Unit Power Agreements” and “I&M Barging, Urea Transloading and Other Services” below for additional information. (b) Refer to the Ohio Auctions section below for further information regarding these amounts.
Affiliated Purchases	Related Party Purchases I&M OPCo (in millions) Year Ended December 31, 2022 Auction Purchases from AEPEP (a) $ — $ 9.8 Direct Purchases from AEGCo 241.8 — Total Affiliated Purchases $ 241.8 $ 9.8 Related Party Purchases I&M OPCo (in millions) Year Ended December 31, 2021 Auction Purchases from AEPEP (a) $ — $ 26.6 Auction Purchases from AEP Energy (a) — 25.3 Direct Purchases from AEGCo 217.9 — Total Affiliated Purchases $ 217.9 $ 51.9 Related Party Purchases I&M OPCo (in millions) Year Ended December 31, 2020 Auction Purchases from AEPEP (a) $ — $ 51.0 Auction Purchases from AEP Energy (a) — 58.7 Auction Purchases from AEPSC (a) — 10.0 Direct Purchases from AEGCo 172.8 — Total Affiliated Purchases $ 172.8 $ 119.7 (a) Refer to the Ohio Auctions section below for further information regarding this amount.
PJM Transmission Service Charges	Years Ended December 31, Company 2022 2021 2020 (in millions) APCo $ 345.1 $ 302.0 $ 243.2 I&M 220.8 186.7 145.9 OPCo 608.2 508.9 417.4
SPP Transmission Service Charges	Years Ended December 31, Company 2022 2021 2020 (in millions) PSO $ 110.8 $ 94.7 $ 69.7 SWEPCo 62.1 56.2 31.3
Joint License Agreement	Years Ended December 31, Billing Company 2022 2021 2020 (in millions) APCo $ 2.5 $ 2.4 $ 0.9 I&M 6.1 4.8 3.0 KPCo 0.6 0.5 0.4 OPCo 5.2 4.6 4.5 PSO 0.1 0.4 0.4 WPCo 0.2 0.2 0.2
Railcar Maintenance	Years Ended December 31, Company 2022 2021 2020 (in millions) I&M $ 0.6 $ 0.3 $ 0.9 PSO 0.6 0.4 0.7 SWEPCo 2.7 2.8 3.0
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2022 2021 2020 (in millions) AEGCo $ 11.3 $ 7.6 $ 10.6 APCo 36.1 40.1 43.7 KPCo 2.0 3.1 3.2 WPCo 4.7 3.2 3.3
Related Party Sales of Property	Sales Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 3.0 $ 0.4 $ 0.9 AEPTCo 2.3 1.4 0.2 APCo 16.0 6.2 5.7 I&M 5.3 7.0 1.5 OPCo 7.6 9.2 7.0 PSO 2.5 0.5 1.1 SWEPCo 1.0 0.4 0.8
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 1.3 $ 0.4 $ 1.5 AEPTCo 11.6 16.7 6.0 APCo 2.4 1.0 1.3 I&M 2.0 0.6 3.4 OPCo 2.0 1.4 1.2 PSO 7.6 0.3 0.4 SWEPCo 2.8 0.3 2.8
Charitable Contribution to AEP Foundation [Table Text Block]	Year Ended Company December 31, 2022 (in millions) AEP $ 75.0 AEP Texas 9.9 AEPTCo 11.1 APCo 12.5 I&M 11.0 OPCo 8.1 PSO 5.8 SWEPCo 8.8

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
Variable Interest Entities (Tables)	Dec. 31, 2022
Consolidated Assets And Liabilities Of Variable Interest Entities	American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2022 Registrant Subsidiaries SWEPCo I&M AEP Texas Transition Funding AEP Texas Restoration Funding APCo (in millions) ASSETS Current Assets $ 108.3 $ 90.2 $ 27.0 $ 21.1 $ 13.5 Net Property, Plant and Equipment 7.2 179.1 — — — Other Noncurrent Assets 130.0 94.0 140.9 (a) 168.8 (b) 164.6 (c) Total Assets $ 245.5 $ 363.3 $ 167.9 $ 189.9 $ 178.1 LIABILITIES AND EQUITY Current Liabilities $ 25.4 $ 90.0 $ 73.2 $ 31.3 $ 29.3 Noncurrent Liabilities 219.4 273.3 90.4 157.4 146.9 Equity 0.7 — 4.3 1.2 1.9 Total Liabilities and Equity $ 245.5 $ 363.3 $ 167.9 $ 189.9 $ 178.1 (a) Includes an intercompany item eliminated in consolidation of $16 million . (b) Includes an intercompany item eliminated in consolidation of $7 million . (c) Includes an intercompany item eliminated in consolidation of $2 million . American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2022 Other Consolidated VIEs AEP Credit Protected Transource Energy Apple Blossom and Black Oak Santa Rita East Dry Lake (in millions) ASSETS Current Assets $ 1,181.0 $ 194.5 $ 23.5 $ 8.3 $ 21.3 $ 4.0 Net Property, Plant and Equipment — — 482.3 216.5 421.6 142.6 Other Noncurrent Assets 9.0 0.3 2.7 13.6 0.1 0.3 Total Assets $ 1,190.0 $ 194.8 $ 508.5 $ 238.4 $ 443.0 $ 146.9 LIABILITIES AND EQUITY Current Liabilities $ 1,087.8 $ 46.4 $ 22.8 $ 4.5 $ 9.6 $ 1.0 Noncurrent Liabilities 0.9 79.1 218.6 5.4 7.3 0.7 Equity 101.3 69.3 267.1 228.5 426.1 145.2 Total Liabilities and Equity $ 1,190.0 $ 194.8 $ 508.5 $ 238.4 $ 443.0 $ 146.9 American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2021 Registrant Subsidiaries SWEPCo I&M AEP Texas Transition Funding AEP Texas Restoration Funding APCo (in millions) ASSETS Current Assets $ 77.2 $ 65.2 $ 24.9 $ 24.3 $ 16.0 Net Property, Plant and Equipment 51.8 118.6 — — — Other Noncurrent Assets 104.1 57.2 208.3 (a) 192.6 (b) 187.8 (c) Total Assets $ 233.1 $ 241.0 $ 233.2 $ 216.9 $ 203.8 LIABILITIES AND EQUITY Current Liabilities $ 18.9 $ 65.1 $ 71.2 $ 36.1 $ 29.0 Noncurrent Liabilities 214.3 175.9 157.8 179.6 172.9 Equity (0.1) — 4.2 1.2 1.9 Total Liabilities and Equity $ 233.1 $ 241.0 $ 233.2 $ 216.9 $ 203.8 (a) Includes an intercompany item eliminated in consolidation of $24 million. (b) Includes an intercompany item eliminated in consolidation of $8 million. (c) Includes an intercompany item eliminated in consolidation of $2 million. American Electric Power Company, Inc. and Subsidiary Companies Variable Interest Entities December 31, 2021 Other Consolidated VIEs AEP Credit Protected Transource Energy Apple Blossom and Black Oak Santa Rita East Dry Lake (in millions) ASSETS Current Assets $ 996.6 $ 217.3 $ 38.8 $ 9.9 $ 7.6 $ 4.0 Net Property, Plant and Equipment — — 475.4 217.3 437.6 146.1 Other Noncurrent Assets 10.4 — 3.0 11.3 — 0.3 Total Assets $ 1,007.0 $ 217.3 $ 517.2 $ 238.5 $ 445.2 $ 150.4 LIABILITIES AND EQUITY Current Liabilities $ 953.1 $ 37.5 $ 12.5 $ 6.6 $ 5.8 $ 0.9 Noncurrent Liabilities 0.9 82.3 216.9 5.2 7.0 0.6 Equity 53.0 97.5 287.8 226.7 432.4 148.9 Total Liabilities and Equity $ 1,007.0 $ 217.3 $ 517.2 $ 238.5 $ 445.2 $ 150.4
SWEPCo's Investment In DHLC	December 31, 2022 2021 As Reported on Maximum As Reported on Maximum (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 0.4 0.4 23.8 23.8 SWEPCo’s Share of Obligations — 36.8 — 50.3 Total Investment in DHLC $ 8.0 $ 44.8 $ 31.4 $ 81.7
AEP's Investment In OVEC	December 31, 2022 2021 As Reported on Maximum As Reported on Maximum Exposure (in millions) Capital Contribution from AEP $ 4.4 $ 4.4 $ 4.4 $ 4.4 AEP’s Ratio of OVEC Debt (a) — 478.2 — 492.0 Total Investment in OVEC $ 4.4 $ 482.6 $ 4.4 $ 496.4 (a) Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $173 million, $86 million and $219 million
Purchased Power from OVEC	Years Ended December 31, Company 2022 2021 2020 (in millions) APCo $ 119.3 $ 104.3 $ 94.4 I&M 59.7 52.2 47.2 OPCo 151.8 133.0 120.8
Billings from Significant Variable Interest	Years Ended December 31, Company 2022 2021 2020 (in millions) AEP Texas $ 236.8 $ 206.9 $ 199.4 AEPTCo 286.6 267.1 270.3 APCo 347.5 313.3 294.9 I&M 192.4 200.9 210.2 OPCo 272.5 234.9 232.8 PSO 142.3 123.7 113.2 SWEPCo 192.5 168.6 161.8
Carrying Amount and Classification of Variable Interest in Accounts Payable	December 31, 2022 2021 Company As Reported on Maximum As Reported on Maximum (in millions) AEP Texas $ 27.8 $ 27.8 $ 22.2 $ 22.2 AEPTCo 31.6 31.6 23.3 23.3 APCo 41.5 41.5 44.1 44.1 I&M 27.7 27.7 21.8 21.8 OPCo 31.1 31.1 25.5 25.5 PSO 17.7 17.7 13.7 13.7 SWEPCo 23.8 23.8 20.5 20.5

Property, Plant and Equipment_2

Property, Plant and Equipment (Tables)	12 Months Ended
Property, Plant and Equipment (Tables)	Dec. 31, 2022
Property, Plant and Equipment	December 31, 2022 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Regulated Property, Plant and Equipment Generation $ 23,759.7 (a) $ — $ — $ 6,776.8 $ 5,534.6 $ — $ 2,394.8 $ 5,476.2 (a) Transmission 33,221.7 6,301.5 12,335.4 4,482.8 1,842.2 3,198.6 1,164.4 2,479.8 Distribution 27,138.8 5,312.8 — 4,933.0 3,024.7 6,450.3 3,216.4 2,659.6 Other 5,528.9 1,020.4 476.6 849.2 796.1 1,040.6 466.0 582.6 CWIP 4,776.4 (a) 805.2 1,554.7 705.3 253.0 474.3 219.3 369.5 (a) Less: Accumulated Depreciation 23,118.0 1,759.5 1,027.1 5,397.3 4,117.8 2,564.3 1,839.4 3,314.8 Total Regulated Property, Plant and Equipment - Net 71,307.5 11,680.4 13,339.6 12,349.8 7,332.8 8,599.5 5,621.5 8,252.9 Nonregulated Property, Plant and Equipment - Net 2,031.6 1.2 0.3 29.4 78.7 9.8 5.0 9.3 Total Property, Plant and Equipment - Net $ 73,339.1 $ 11,681.6 $ 13,339.9 $ 12,379.2 $ 7,411.5 $ 8,609.3 $ 5,626.5 $ 8,262.2 December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) (as adjusted) Regulated Property, Plant and Equipment Generation $ 22,428.3 (a) $ — $ — $ 6,683.9 $ 5,531.8 $ — $ 1,802.4 $ 4,734.5 (a) Transmission 30,771.1 5,849.9 11,031.0 4,322.4 1,783.1 2,992.8 1,107.7 2,316.9 Distribution 25,457.4 4,917.2 — 4,683.3 2,800.1 6,070.6 3,004.9 2,514.3 Other 5,403.5 958.7 451.7 668.9 755.1 982.2 433.5 542.0 CWIP 3,734.8 (a) 551.3 1,402.2 469.9 302.8 365.0 156.0 240.7 (a) Less: Accumulated Depreciation 21,491.1 1,642.9 784.0 5,047.4 3,885.3 2,457.4 1,707.0 3,002.2 Total Regulated Property, Plant and Equipment - Net 66,304.0 10,634.2 12,100.9 11,781.0 7,287.6 7,953.2 4,797.5 7,346.2 Nonregulated Property, Plant and Equipment - Net 2,000.1 1.2 0.1 23.3 23.3 9.8 5.3 53.9 Total Property, Plant and Equipment - Net $ 68,304.1 $ 10,635.4 $ 12,101.0 $ 11,804.3 $ 7,310.9 $ 7,963.0 $ 4,802.8 $ 7,400.1 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Depreciation, Depletion and Amortization - Regulated	AEP 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 2.7% - 7.6% 20 - 132 2.7% - 7.8% 20 - 132 2.7% - 6.3% 20 - 132 Transmission 2.0% - 2.7% 24 - 75 2.0% - 2.6% 15 - 75 2.0% - 2.6% 15 - 75 Distribution 2.7% - 3.6% 7 - 78 2.8% - 3.6% 7 - 80 2.7% - 3.7% 7 - 78 Other 3.1% - 14.4% 5 - 75 3.0% - 12.5% 5 - 75 2.8% - 11.3% 5 - 75 AEP Texas 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Transmission 2.2% 50 - 75 2.2% 50 - 75 2.0% 50 - 75 Distribution 2.9% 7 - 70 2.9% 7 - 70 3.1% 7 - 70 Other 6.2% 5 - 50 5.8% 5 - 50 6.1% 5 - 50 AEPTCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Transmission 2.6% 24 - 75 2.5% 24 - 75 2.4% 24 - 75 Other 6.6% 5 - 56 6.7% 5 - 56 6.3% 5 - 64 APCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 3.6% 35 - 118 3.6% 35 - 118 3.3% 35 - 118 Transmission 2.2% 24 - 75 2.1% 15 - 75 2.2% 15 - 75 Distribution 3.6% 12 - 57 3.5% 12 - 57 3.7% 12 - 57 Other 7.3% 5 - 55 8.5% 5 - 55 7.8% 5 - 55 I&M 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 4.9% 20 - 132 4.7% 20 - 132 4.6% 20 - 132 Transmission 2.5% 44 - 67 2.4% 45 - 70 2.3% 45 - 70 Distribution 3.1% 14 - 71 3.4% 14 - 71 3.4% 14 - 71 Other 10.1% 5 - 45 9.0% 5 - 51 10.2% 5 - 51 OPCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.7% 11 - 70 2.9% 11 - 70 3.1% 14 - 65 Other 6.1% 5 - 50 6.1% 5 - 50 5.0% 5 - 50 PSO 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 3.1% 30 - 75 2.8% 30 - 75 3.1% 35 - 75 Transmission 2.5% 42 - 75 2.4% 42 - 75 2.2% 45 - 75 Distribution 2.9% 15 - 78 2.9% 15 - 78 2.9% 15 - 78 Other 6.8% 5 - 56 6.1% 5 - 56 5.7% 5 - 64 SWEPCo 2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 2.7% 30 - 65 2.7% 30 - 65 2.7% 35 - 65 Transmission 2.3% 44 - 70 2.4% 49 - 74 2.3% 47 - 73 Distribution 2.9% 15 - 75 2.8% 15 - 80 2.7% 15 - 67 Other 9.0% 5 - 57 8.6% 5 - 58 8.5% 5 - 52
Depreciation, Depletion and Amortization - Unregulated	2022 2021 2020 Functional Class of Property Annual Composite Depreciable Annual Composite Depreciable Annual Composite Depreciable (in years) (in years) (in years) Generation 3.8% - 8.7% 3 - 61 3.8% - 10.4% 10 - 59 3.6% - 4.0% 15 - 59 Transmission 2.8% 10 - 62 2.6% 30 - 40 2.5% 30 - 40 Distribution NA NA NA NA NA NA Other 25.2% 5 - 35 (a) 16.5% 5 - 35 (a) 16.1% 5 - 50 (a) In 2020 management announced plans to retire the Pirkey Plant in 2023 and the related depreciable lives have been adjusted accordingly. See Note 5 - Effects of Regulation for additional information. NA Not applicable.
Allowance For Equity Funds Used During Construction	Years Ended December 31, Company 2022 2021 2020 (in millions) AEP $ 133.7 $ 139.7 $ 148.1 AEP Texas 19.7 21.5 19.4 AEPTCo 70.7 67.2 74.0 APCo 11.7 15.6 14.6 I&M 9.8 12.8 11.5 OPCo 13.9 10.8 12.5 PSO 1.5 2.4 4.0 SWEPCo 4.9 7.0 7.7
Allowance For Borrowed Funds Used During Construction	Years Ended December 31, Company 2022 2021 2020 (in millions) AEP $ 63.0 $ 53.8 $ 66.0 AEP Texas 11.5 10.5 12.5 AEPTCo 22.4 21.0 25.5 APCo 6.5 7.5 7.9 I&M 5.7 5.1 5.7 OPCo 6.7 4.7 6.2 PSO 2.7 0.7 2.0 SWEPCo 4.3 3.0 3.9
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2022 Fuel Percent of Utility Plant Construction Accumulated (in millions) AEP Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 382.9 $ 16.4 $ 149.4 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 632.0 — 632.0 Turk Generating Plant (a) Coal 73.3 % 1,611.1 5.1 314.7 Total $ 2,626.0 $ 21.5 $ 1,096.1 I&M Rockport Generating Plant (b)(c)(d) Coal 50.0 % $ 1,357.4 $ 9.2 $ 905.1 PSO North Central Wind Energy Facilities (e)(f) Wind 45.5 % $ 889.3 $ 9.1 $ 28.1 SWEPCo Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 382.9 $ 16.4 $ 149.4 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 632.0 — 632.0 Turk Generating Plant (a) Coal 73.3 % 1,611.1 5.1 314.7 North Central Wind Energy Facilities (e)(f) Wind 54.5 % 1,066.8 10.1 35.2 Total $ 3,692.8 $ 31.6 $ 1,131.3 Registrant’s Share as of December 31, 2021 Fuel Percent of Utility Plant Construction Accumulated (in millions) AEP Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 377.6 $ 6.3 $ 133.5 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 613.8 — 528.3 Turk Generating Plant (a) Coal 73.3 % 1,598.0 10.2 285.6 Total $ 2,589.4 $ 16.5 $ 947.4 I&M Rockport Generating Plant (b)(c)(d) Coal 50.0 % $ 1,247.2 $ 13.9 $ 794.5 PSO North Central Wind Energy Facilities (e)(f) Wind 45.5 % $ 313.7 $ — $ 4.2 SWEPCo Flint Creek Generating Station, Unit 1 (a) Coal 50.0 % $ 377.6 $ 6.3 $ 133.5 Pirkey Plant, Unit 1 (a) Lignite 85.9 % 613.8 — 528.3 Turk Generating Plant (a) Coal 73.3 % 1,598.0 10.2 285.6 North Central Wind Energy Facilities (e)(f) Wind 54.5 % 376.2 — 5.4 Total $ 2,965.6 $ 16.5 $ 952.8 (a) Operated by SWEPCo. (b) Operated by I&M. (c) Amounts include I&M's 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 was subject to a finance lease with a nonaffiliated company. In December 2022, the lease expired at which point I&M and AEGCo acquired 100% of the interests in Unit 2. See the "Rockport Plant Litigation" section of Note 6 for additional information. (d) AEGCo owns 50%. (e) PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Sundance was placed into service in April 2021. Maverick was placed into service in September 2021. Traverse was placed into service in March 2022. See the “Acquisitions” section of Note 7 for additional information. (f) Operated by PSO.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
Revenue from Contracts with Customers (Tables)	Dec. 31, 2022
Disaggregated Revenues from Contracts with Customers	Year Ended December 31, 2022 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 $ 4,498.6 $ 2,497.3 $ — $ — $ — $ — $ 6,995.9 Commercial Revenues 2,576.5 1,365.2 — — — — 3,941.7 Industrial Revenues (a) 2,543.8 711.3 — — — (0.9) 3,254.2 Other Retail Revenues 212.2 49.1 — — — — 261.3 Total Retail Revenues 9,831.1 4,622.9 — — — (0.9) 14,453.1 Wholesale and Competitive Retail Revenues: Generation Revenues 958.3 — — 271.2 — — 1,229.5 Transmission Revenues (b) 442.8 650.0 1,700.6 — — (1,413.2) 1,380.2 Renewable Generation Revenues (a) — — — 129.1 — (8.0) 121.1 Retail, Trading and Marketing Revenues (a) — — — 1,713.2 6.9 (10.1) 1,710.0 Total Wholesale and Competitive Retail Revenues 1,401.1 650.0 1,700.6 2,113.5 6.9 (1,431.3) 4,440.8 Other Revenues from Contracts with Customers (c) 241.1 247.3 8.2 12.1 93.9 (104.8) 497.8 Total Revenues from Contracts with Customers 11,473.3 5,520.2 1,708.8 2,125.6 100.8 (1,537.0) 19,391.7 Other Revenues: Alternative Revenue Programs (d) 3.8 (26.8) (31.8) — — (57.7) (112.5) Other Revenues (a) (e) 0.4 18.6 — 341.3 9.1 (9.1) 360.3 Total Other Revenues 4.2 (8.2) (31.8) 341.3 9.1 (66.8) 247.8 Total Revenues $ 11,477.5 $ 5,512.0 $ 1,677.0 $ 2,466.9 $ 109.9 $ (1,603.8) $ 19,639.5 (a) Amounts include affiliated and nonaffiliated revenues. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.3 billion. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $59 million. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Generation & Marketing includes economic hedge activity. Year Ended December 31, 2021 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 3,952.6 $ 2,138.2 $ — $ — $ — $ — $ 6,090.8 Commercial Revenues 2,208.5 1,081.2 — — — — 3,289.7 Industrial Revenues 2,168.2 395.2 — — — (0.8) 2,562.6 Other Retail Revenues 170.6 43.9 — — — — 214.5 Total Retail Revenues 8,499.9 3,658.5 — — — (0.8) 12,157.6 Wholesale and Competitive Retail Revenues: Generation Revenues 942.6 — — 137.9 — — 1,080.5 Transmission Revenues (a) 355.5 572.4 1,456.4 — — (1,206.0) 1,178.3 Renewable Generation Revenues (b) — — — 86.9 — (3.6) 83.3 Retail, Trading and Marketing Revenues (c) — — — 1,722.6 1.4 (51.6) 1,672.4 Total Wholesale and Competitive Retail Revenues 1,298.1 572.4 1,456.4 1,947.4 1.4 (1,261.2) 4,014.5 Other Revenues from Contracts with Customers (b) 187.5 194.2 17.1 7.2 60.1 (115.2) 350.9 Total Revenues from Contracts with Customers 9,985.5 4,425.1 1,473.5 1,954.6 61.5 (1,377.2) 16,523.0 Other Revenues: Alternative Revenue Programs (d) 13.5 48.8 52.7 — — (73.6) 41.4 Other Revenues (b) (e) (0.5) 19.0 — 209.1 10.7 (10.7) 227.6 Total Other Revenues 13.0 67.8 52.7 209.1 10.7 (84.3) 269.0 Total Revenues $ 9,998.5 $ 4,492.9 $ 1,526.2 $ 2,163.7 $ 72.2 $ (1,461.5) $ 16,792.0 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.1 billion. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $52 million. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Generation & Marketing includes economic hedge activity. Year Ended December 31, 2020 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 3,606.8 $ 2,086.9 $ — $ — $ — $ — $ 5,693.7 Commercial Revenues 2,016.2 1,048.6 — — — — 3,064.8 Industrial Revenues 2,018.0 390.1 — — — (0.7) 2,407.4 Other Retail Revenues 155.6 42.5 — — — — 198.1 Total Retail Revenues 7,796.6 3,568.1 — — — (0.7) 11,364.0 Wholesale and Competitive Retail Revenues: Generation Revenues 588.3 — — 131.9 — — 720.2 Transmission Revenues (a) 334.5 467.0 1,257.0 — — (1,006.7) 1,051.8 Renewable Generation Revenues (b) — — — 60.9 — (1.6) 59.3 Retail, Trading and Marketing Revenues (c) — — — 1,486.9 (5.5) (103.0) 1,378.4 Total Wholesale and Competitive Retail Revenues 922.8 467.0 1,257.0 1,679.7 (5.5) (1,111.3) 3,209.7 Other Revenues from Contracts with Customers (b) 163.2 157.8 22.4 2.3 92.5 (148.6) 289.6 Total Revenues from Contracts with Customers 8,882.6 4,192.9 1,279.4 1,682.0 87.0 (1,260.6) 14,863.3 Other Revenues: Alternative Revenue Programs (d) (3.2) 70.0 (80.6) — — 7.5 (6.3) Other Revenues (b) (e) — 83.0 — 43.6 9.8 (74.9) 61.5 Total Other Revenues (3.2) 153.0 (80.6) 43.6 9.8 (67.4) 55.2 Total Revenues $ 8,879.4 $ 4,345.9 $ 1,198.8 $ 1,725.6 $ 96.8 $ (1,328.0) $ 14,918.5 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $965 million. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $103 million. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Generation & Marketing includes economic hedge activity. Year Ended December 31, 2022 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 667.2 $ — $ 1,558.7 $ 852.4 $ 1,830.2 $ 816.3 $ 820.7 Commercial Revenues 417.5 — 643.4 550.2 947.7 489.2 612.3 Industrial Revenues (a) 139.6 — 664.0 602.9 571.7 372.5 393.5 Other Retail Revenues 35.3 — 87.1 5.0 13.9 102.9 10.1 Total Retail Revenues 1,259.6 — 2,953.2 2,010.5 3,363.5 1,780.9 1,836.6 Wholesale Revenues: Generation Revenues (b) — — 299.9 490.0 — 26.5 273.2 Transmission Revenues (c) 563.8 1,643.5 167.0 36.8 86.2 39.2 148.7 Total Wholesale Revenues 563.8 1,643.5 466.9 526.8 86.2 65.7 421.9 Other Revenues from Contracts with Customers (d) 24.6 8.2 100.6 122.4 222.4 29.1 24.7 Total Revenues from Contracts with Customers 1,848.0 1,651.7 3,520.7 2,659.7 3,672.1 1,875.7 2,283.2 Other Revenues: Alternative Revenue Programs (e) (1.2) (27.2) (1.3) 10.0 (25.6) (1.0) 1.2 Other Revenues (a) — — 0.5 (0.1) 18.6 — — Total Other Revenues (1.2) (27.2) (0.8) 9.9 (7.0) (1.0) 1.2 Total Revenues $ 1,846.8 $ 1,624.5 $ 3,519.9 $ 2,669.6 $ 3,665.1 $ 1,874.7 $ 2,284.4 (a) Amounts include affiliated and nonaffiliated revenues. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $170 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.3 billion, APCo was $78 million and SWEPCo was $51 million. The remaining affiliated amounts were immaterial. (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $62 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Year Ended December 31, 2021 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 550.3 $ — $ 1,379.6 $ 805.4 $ 1,587.9 $ 651.9 $ 709.5 Commercial Revenues 358.5 — 556.3 507.2 722.7 378.9 529.3 Industrial Revenues 108.9 — 584.3 557.0 286.3 274.1 344.4 Other Retail Revenues 31.3 — 70.8 5.2 12.6 77.7 10.0 Total Retail Revenues 1,049.0 — 2,591.0 1,874.8 2,609.5 1,382.6 1,593.2 Wholesale Revenues: Generation Revenues (a) — — 302.7 318.1 — 22.9 386.6 Transmission Revenues (b) 497.5 1,393.9 128.8 33.7 74.9 37.5 122.7 Total Wholesale Revenues 497.5 1,393.9 431.5 351.8 74.9 60.4 509.3 Other Revenues from Contracts with Customers (c) 41.2 17.0 70.4 104.1 153.1 31.3 23.5 Total Revenues from Contracts with Customers 1,587.7 1,410.9 3,092.9 2,330.7 2,837.5 1,474.3 2,126.0 Other Revenues: Alternative Revenue Programs (d) 6.1 58.4 12.3 (4.0) 42.6 0.1 5.8 Other Revenues (e) — — — — 19.0 — — Total Other Revenues 6.1 58.4 12.3 (4.0) 61.6 0.1 5.8 Total Revenues $ 1,593.8 $ 1,469.3 $ 3,105.2 $ 2,326.7 $ 2,899.1 $ 1,474.4 $ 2,131.8 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.1 billion. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $60 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Amounts include affiliated and nonaffiliated revenues. Year Ended December 31, 2020 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 563.6 $ — $ 1,250.6 $ 794.1 $ 1,523.4 $ 579.4 $ 630.8 Commercial Revenues 366.7 — 517.0 499.3 682.0 320.1 466.7 Industrial Revenues 120.1 — 553.5 547.4 270.0 221.1 328.8 Other Retail Revenues 29.5 — 67.6 6.6 13.1 66.0 9.1 Total Retail Revenues 1,079.9 — 2,388.7 1,847.4 2,488.5 1,186.6 1,435.4 Wholesale Revenues: Generation Revenues (a) — — 230.2 274.6 — 15.1 162.0 Transmission Revenues (b) 399.9 1,210.3 130.8 29.0 67.0 27.5 111.2 Total Wholesale Revenues 399.9 1,210.3 361.0 303.6 67.0 42.6 273.2 Other Revenues from Contracts with Customers (c) 48.2 22.4 59.5 85.0 109.5 34.7 26.7 Total Revenues from Contracts with Customers 1,528.0 1,232.7 2,809.2 2,236.0 2,665.0 1,263.9 1,735.3 Other Revenues: Alternative Revenue Programs (d) 3.4 (87.0) (13.0) 5.8 66.6 2.2 3.2 Other Revenues (e) 87.5 — — — 17.5 — — Total Other Revenues 90.9 (87.0) (13.0) 5.8 84.1 2.2 3.2 Total Revenues $ 1,618.9 $ 1,145.7 $ 2,796.2 $ 2,241.8 $ 2,749.1 $ 1,266.1 $ 1,738.5 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $112 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $952 million. The remaining affiliated amounts were immaterial. (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $69 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. (e) Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations	Company 2023 2024-2025 2026-2027 After 2027 Total (in millions) AEP $ 85.5 $ 157.3 $ 133.9 $ 60.3 $ 437.0 APCo 16.1 32.2 23.2 11.7 83.2 I&M 4.6 9.2 9.2 4.5 27.5
Affiliated Accounts Receivable Contracts with Customers	Years Ended December 31, Company 2022 2021 (in millions) AEP Texas $ 0.1 $ 0.4 AEPTCo 113.8 95.5 APCo 64.5 117.8 I&M 75.3 61.2 OPCo 49.9 51.7 PSO 18.8 18.8 SWEPCo 19.1 24.7

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
Goodwill (Tables)	Dec. 31, 2022
Changes in Carrying Amount of Goodwill	Corporate and Other Generation AEP Consolidated (in millions) Balance as of December 31, 2020 $ 37.1 $ 15.4 $ 52.5 Impairment Losses — — — Balance as of December 31, 2021 37.1 15.4 52.5 Impairment Losses — — — Balance as of December 31, 2022 $ 37.1 $ 15.4 $ 52.5

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Materials and Supplies		$ 915.1	$ 701.8
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		3,072.8	2,717.1	$ 2,487.5
Amortization of Certain Securitized Assets		93.3	64.2	171.3
Amortization of Regulatory Assets and Liabilities		36.7	44.4	24
Total Depreciation and Amortization		3,202.8	2,825.7	2,682.8
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		403.4
Restricted Cash		47.1	48
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		556.5	451.4	438.3	$ 432.6
Amounts Attributable to AEP Common Shareholders
Net Income (Loss) Attributable to Noncontrolling Interests		(1.6)	0	(3.4)
Net Income (Loss)		$ 2,307.2	$ 2,488.1	$ 2,200.1
Weighted Average Number of Basic AEP Common Shares Outstanding		511,841,946	500,522,177	495,718,223
Earnings Per Share, Basic		$ 4.51	$ 4.97	$ 4.44
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding		513,484,609	501,784,032	497,226,867
Earnings Per Share, Diluted		$ 4.49	$ 4.96	$ 4.42
Revenues
TOTAL REVENUES		$ 19,639.5	$ 16,792	$ 14,918.5
Expenses
Depreciation and Amortization		3,202.8	2,825.7	2,682.8
TOTAL EXPENSES		16,156.8	13,380.7	11,930.8
OPERATING INCOME (LOSS)		3,482.7	3,411.3	2,987.7
Other Income (Expense)
Allowance for Equity Funds Used During Construction		133.7	139.7	148.1
Interest Expense		(1,396.1)	(1,199.1)	(1,165.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		2,420.4	2,511.9	2,146.1
Income Tax Expense/Benefit		5.4	115.5	40.5
Net Income (Loss)		2,305.6	2,488.1	2,196.7
Accounts Receivable:
Customers		1,145.1	737.4
Total Accounts Receivable		2,668	1,974.9
Accrued Tax Benefits		99.4	121.5
TOTAL CURRENT ASSETS		6,775.5	4,984.4
Property, Plant and Equipment
Transmission		33,266.9	30,816.3
Other Property, Plant and Equipment		5,971.8	5,844.9
Construction Work in Progress		4,809.7	3,786.8
Total Property, Plant and Equipment		97,021.4	90,225
Accumulated Depreciation and Amortization		23,682.3	21,920.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		73,339.1	68,304.1
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		13,288.7	14,380.2
TOTAL ASSETS		93,403.3	87,668.7
Current Liabilities
Accounts Payable		2,670.8	2,108
Accrued Taxes		1,714.6	1,631.3
TOTAL CURRENT LIABILITIES		13,266.3	10,906.4
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		8,115.6	8,834.4
TOTAL NONCURRENT LIABILITIES		55,968.7	54,038.8
TOTAL LIABILITIES		69,235	64,945.2
Equity [Abstract]
Retained Earnings		12,345.6	11,667.1
TOTAL LIABILITIES AND EQUITY		93,403.3	87,668.7
Operating Activites
Net Income (Loss)		2,305.6	2,488.1	2,196.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		3,202.8	2,825.7	2,682.8
Deferred Income Taxes		(137.2)	107.6	196.1
Allowance for Equity Funds Used During Construction		(133.7)	(139.7)	(148.1)
Amortization of Deferred Property Taxes		(41.2)	(68)	(43.3)
Change in Other Noncurrent Assets		(187.7)	(126.6)	(151)
Increase (Decrease) in Other Noncurrent Liabilities		337.8	206.4	(54.5)
Accounts Receivable, Net		(681.7)	(119.7)	(129.3)
Accounts Payable		489.2	200.6	(35.3)
Accrued Taxes, Net		105.4	218.7	20.1
Net Cash Flows from Operating Activities		5,288	3,839.9	3,832.9
Investing Activities
Net Cash Flows Used for Investing Activities		(7,751.8)	(6,433.9)	(6,233.9)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		2,568.9	2,607.1	2,406.7
Cash and Cash Equivalents at Beginning of Period		403.4
Cash and Cash Equivalents at End of Period		509.4	403.4
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		1,286.3	1,137.2	1,029.1
Income Taxes		116.8	13.2	(49.1)
Noncash Investing and Financing Activities:
Noncash Acquisition Under Finance Leases		31.8	287.6	44.2
Construction in Progress Expenditures Incurred but Not yet Paid		1,258.9	1,180.4	975.4
Construction Expenditures Included in Current Liabilities as of December 31,		1,258.9	1,180.4	975.4
Construction Expenditures Included in Noncurrent Liabilities as of December 31,		0	0	5.5
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,		0	0	33.4
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,		56.4	47.8	(86.2)
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		4,649.7	6,486.3	5,626.1
Repayments of Long-term Debt		$ 2,345.4	2,989.3	1,339.8
Equity Method Investment, Ownership Percentage		50%
Equity Method Investment		$ 1,276.7	1,447.5	1,406.3
Income (Loss) from Equity Method Investment		$ (109.4)	$ 91.7	$ 91.1
Antidilutive Shares Outstanding		0	0	128,000
Net Income (Loss)		$ 2,305.6	$ 2,488.1	$ 2,196.7
Retained Earnings		12,345.6	11,667.1
2020 Equity Units [Member]
Noncash Investing and Financing Activities:
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,		0	0	110.6
Cedar Creek Project
Noncash Investing and Financing Activities:
Noncash Contribution of Assets to Cedar Creek Project		0	(9.3)	0
Retained Earnings [Member]
Amounts Attributable to AEP Common Shareholders
Net Income (Loss)		2,307.2	2,488.1	2,200.1
Noncash Investing and Financing Activities:
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,			(1.1)
Berkshire Hathaway [Member]
Organization and Summary of Significant Accounting Policies (Textuals)
Equity Method Investment, Ownership Percentage		50%
AEP Transmission Holdco [Member]
Organization and Summary of Significant Accounting Policies (Textuals)
Equity Method Investment, Ownership Percentage		50%
Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	137
AEP Texas Inc. [Member]
Materials and Supplies		138.8	73.9
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		363.5	327.2	364.2
Amortization of Certain Securitized Assets		93.3	64.2	171.3
Amortization of Regulatory Assets and Liabilities		(4.4)	(4.4)	(5.7)
Total Depreciation and Amortization		452.4	387	529.8
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		0.1
Restricted Cash		32.7	30.4
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		32.8	30.5	28.8	157.8
Revenues
TOTAL REVENUES		1,846.8	1,593.8	1,618.9
Expenses
Depreciation and Amortization		452.4	387	529.8
TOTAL EXPENSES		1,297.6	1,117.8	1,249.3
OPERATING INCOME (LOSS)		549.2	476	369.6
Other Income (Expense)
Allowance for Equity Funds Used During Construction		19.7	21.5	19.4
Interest Expense		(208.7)	(176.5)	(171.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		380.5	332.9	229.8
Income Tax Expense/Benefit		72.6	43.1	(11.2)
Net Income (Loss)		307.9	289.8	241
Accounts Receivable:
Customers		150.9	123.4
Total Accounts Receivable		250.2	205.2
Accrued Tax Benefits		12.2	24.8
TOTAL CURRENT ASSETS		446.9	347.2
Property, Plant and Equipment
Transmission		6,301.5	5,849.9
Other Property, Plant and Equipment		1,022.8	961.1
Construction Work in Progress		805.2	551.3
Total Property, Plant and Equipment		13,442.3	12,279.5
Accumulated Depreciation and Amortization		1,760.7	1,644.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		11,681.6	10,635.4
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		763.7	854.1
TOTAL ASSETS		12,892.2	11,836.7
Current Liabilities
Accounts Payable		331	306.3
Affiliated Companies		34.7	32.5
Accrued Taxes		95.5	93.3
TOTAL CURRENT LIABILITIES		1,043.8	1,311.7
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		1,259.6	1,242
TOTAL NONCURRENT LIABILITIES		7,944.1	6,930.8
TOTAL LIABILITIES		8,987.9	8,242.5
Equity [Abstract]
Retained Earnings		2,354.7	2,046.8
TOTAL LIABILITIES AND EQUITY		12,892.2	11,836.7
Operating Activites
Net Income (Loss)		307.9	289.8	241
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		452.4	387	529.8
Deferred Income Taxes		42.2	43	(15.2)
Allowance for Equity Funds Used During Construction		(19.7)	(21.5)	(19.4)
Change in Other Noncurrent Assets		(36.2)	(78.2)	(74)
Increase (Decrease) in Other Noncurrent Liabilities		57.6	26.4	(24.7)
Accounts Receivable, Net		(45)	(21.6)	9.8
Accounts Payable		25	8.9	30.2
Accrued Taxes, Net		14.8	7	42.7
Net Cash Flows from Operating Activities		731.9	596.6	614.2
Investing Activities
Net Cash Flows Used for Investing Activities		(1,269.9)	(1,000.8)	(1,065.4)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		540.3	405.9	322.2
Cash and Cash Equivalents at Beginning of Period		0.1
Cash and Cash Equivalents at End of Period		0.1	0.1
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		198.9	168.9	153.2
Income Taxes		11	5.7	(42.9)
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		235.4	230	177.8
Construction Expenditures Included in Current Liabilities as of December 31,		235.4	230	177.8
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		1,188.6	444.2	652.7
Repayments of Long-term Debt		716	88.7	392.1
Net Income (Loss)		307.9	289.8	241
Retained Earnings		2,354.7	2,046.8
AEP Texas Inc. [Member] \| Retained Earnings [Member]
Other Income (Expense)
Net Income (Loss)		307.9	289.8	241
Operating Activites
Net Income (Loss)		307.9	289.8	241
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)		$ 307.9	289.8	241
AEP Texas Inc. [Member] \| Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
AEP Texas Inc. [Member] \| Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
AEP Texas Inc. [Member] \| Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
AEP Texas Inc. [Member] \| Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
AEP Texas Inc. [Member] \| Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
AEP Texas Inc. [Member] \| Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
AEP Texas Inc. [Member] \| Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
AEP Texas Inc. [Member] \| Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	137
AEP Transmission Co [Member]
Materials and Supplies		10.7	9.3
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		346.2	297.3	249
Amortization of Certain Securitized Assets		0	0	0
Amortization of Regulatory Assets and Liabilities		0	0	0
Total Depreciation and Amortization		346.2	297.3	249
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		0	0	0
Revenues
TOTAL REVENUES		1,624.5	1,469.3	1,145.7
Expenses
Depreciation and Amortization		346.2	297.3	249
TOTAL EXPENSES		770.8	660	564.2
OPERATING INCOME (LOSS)		853.7	809.3	581.5
Other Income (Expense)
Allowance for Equity Funds Used During Construction		70.7	67.2	74
Interest Expense		(162.7)	(141.2)	(127.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		763.3	735.8	530.1
Income Tax Expense/Benefit		169.1	144.1	106.7
Net Income (Loss)		594.2	591.7	423.4
Accounts Receivable:
Customers		46.9	22.8
Total Accounts Receivable		166.4	120.1
Accrued Tax Benefits		4.2	5.6
TOTAL CURRENT ASSETS		188.7	165
Property, Plant and Equipment
Transmission		12,335.4	11,031
Other Property, Plant and Equipment		476.8	451.9
Construction Work in Progress		1,554.7	1,402.2
Total Property, Plant and Equipment		14,366.9	12,885.1
Accumulated Depreciation and Amortization		1,027	784.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		13,339.9	12,101
Other Noncurrent Assets
Deferred Property Taxes		266.6	245.7
TOTAL OTHER NONCURRENT ASSETS		285.6	258.4
TOTAL ASSETS		13,814.2	12,524.4
Current Liabilities
Accounts Payable		427.8	460.7
Affiliated Companies		82.7	70.4
Accrued Taxes		529.8	481
TOTAL CURRENT LIABILITIES		1,368	1,273.9
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		723.3	651.7
TOTAL NONCURRENT LIABILITIES		6,573.2	5,874.4
TOTAL LIABILITIES		7,941.2	7,148.3
Equity [Abstract]
Retained Earnings		2,850.7	2,426.5
TOTAL MEMBER'S EQUITY		5,873	5,376.1	4,712.9	4,009.5
TOTAL LIABILITIES AND EQUITY		13,814.2	12,524.4
Operating Activites
Net Income (Loss)		594.2	591.7	423.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		346.2	297.3	249
Deferred Income Taxes		62.3	68.5	81.6
Allowance for Equity Funds Used During Construction		(70.7)	(67.2)	(74)
Amortization of Deferred Property Taxes		(20.9)	(25.6)	(26.6)
Change in Other Noncurrent Assets		(7.4)	7.5	(8.2)
Increase (Decrease) in Other Noncurrent Liabilities		68.7	3.7	8.3
Accounts Receivable, Net		(46.3)	(16)	(19)
Accounts Payable		18.5	(2.2)	77.8
Accrued Taxes, Net		50.2	67.2	62.7
Net Cash Flows from Operating Activities		995.3	925.7	771.2
Investing Activities
Net Cash Flows Used for Investing Activities		(1,439.2)	(1,359)	(1,640.4)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		443.9	433.3	869.2
Cash and Cash Equivalents at Beginning of Period		0	0	0
Cash and Cash Equivalents at End of Period		0	0	0
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		158.8	132.9	119.7
Income Taxes		95.5	65.7	22.9
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		320.7	358.7	311.9
Construction Expenditures Included in Current Liabilities as of December 31,		320.7	358.7	311.9
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		540.8	443.7	519.5
Repayments of Long-term Debt		104	50	0
Net Income (Loss)		594.2	591.7	423.4
Retained Earnings		2,850.7	2,426.5
AEP Transmission Co [Member] \| Retained Earnings [Member]
Other Income (Expense)
Net Income (Loss)		594.2	591.7	423.4
Equity [Abstract]
TOTAL MEMBER'S EQUITY		2,850.7	2,426.5	1,947.3	1,528.9
Operating Activites
Net Income (Loss)		594.2	591.7	423.4
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)		594.2	591.7	423.4
Appalachian Power Co [Member]
Materials and Supplies		130.6	109.8
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		576.1	547	507.8
Amortization of Certain Securitized Assets		0	0	0
Amortization of Regulatory Assets and Liabilities		(0.2)	(0.8)	(0.3)
Total Depreciation and Amortization		575.9	546.2	507.5
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		2.5
Restricted Cash		14.4	17.6
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		21.9	20.1	22.7	26.8
Revenues
TOTAL REVENUES		3,519.9	3,105.2	2,796.2
Expenses
Depreciation and Amortization		575.9	546.2	507.5
TOTAL EXPENSES		2,917.8	2,555.8	2,239.6
OPERATING INCOME (LOSS)		602.1	549.4	556.6
Other Income (Expense)
Allowance for Equity Funds Used During Construction		11.7	15.6	14.6
Interest Expense		(233.9)	(214)	(217.6)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		412.4	371	374
Income Tax Expense/Benefit		18.2	22.1	4.3
Net Income (Loss)		394.2	348.9	369.7
Accounts Receivable:
Customers		168.9	158.5
Total Accounts Receivable		352.8	341
TOTAL CURRENT ASSETS		1,259.6	925.3
Property, Plant and Equipment
Transmission		4,482.8	4,322.4
Other Property, Plant and Equipment		883.3	696.6
Construction Work in Progress		705.3	469.9
Total Property, Plant and Equipment		17,781.2	16,856.1
Accumulated Depreciation and Amortization		5,402	5,051.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		12,379.2	11,804.3
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		1,583.4	1,359.3
TOTAL ASSETS		15,222.2	14,088.9
Current Liabilities
Accounts Payable		451.2	262.2
Affiliated Companies		142.7	118.6
Accrued Taxes		101	119.7
TOTAL CURRENT LIABILITIES		1,390.2	1,415.9
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		1,143.6	1,238.8
TOTAL NONCURRENT LIABILITIES		8,856.6	8,025.1
TOTAL LIABILITIES		10,246.8	9,441
Equity [Abstract]
Retained Earnings		2,891.1	2,534.4
TOTAL LIABILITIES AND EQUITY		15,222.2	14,088.9
Operating Activites
Net Income (Loss)		394.2	348.9	369.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		575.9	546.2	507.5
Deferred Income Taxes		79.6	15	(26.2)
Allowance for Equity Funds Used During Construction		(11.7)	(15.6)	(14.6)
Change in Other Noncurrent Assets		(75.2)	(68.8)	(40.4)
Increase (Decrease) in Other Noncurrent Liabilities		31.4	35.6	11.2
Accounts Receivable, Net		(8.5)	(53.3)	(30.2)
Accounts Payable		190.1	36.8	(48.1)
Accrued Taxes, Net		6.7	(16.2)	31.3
Net Cash Flows from Operating Activities		601.2	611.7	712
Investing Activities
Net Cash Flows Used for Investing Activities		(1,005.2)	(826.5)	(757.9)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		405.8	212.2	41.8
Cash and Cash Equivalents at Beginning of Period		2.5
Cash and Cash Equivalents at End of Period		7.5	2.5
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		215.1	207.5	207.1
Income Taxes		(88.6)	32.8	0
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		164.6	139.1	105.6
Construction Expenditures Included in Current Liabilities as of December 31,		164.6	139.1	105.6
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		698	494	606.9
Repayments of Long-term Debt		230.4	393	140.3
Net Income (Loss)		394.2	348.9	369.7
Retained Earnings		2,891.1	2,534.4
Appalachian Power Co [Member] \| Retained Earnings [Member]
Other Income (Expense)
Net Income (Loss)		394.2	348.9	369.7
Operating Activites
Net Income (Loss)		394.2	348.9	369.7
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)		$ 394.2	348.9	369.7
Appalachian Power Co [Member] \| Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
Appalachian Power Co [Member] \| Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
Appalachian Power Co [Member] \| Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
Appalachian Power Co [Member] \| Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Appalachian Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
Appalachian Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
Appalachian Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Appalachian Power Co [Member] \| Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	137
Indiana Michigan Power Co [Member]
Materials and Supplies		188.1	175.2
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		511.9	424.9	393.3
Amortization of Certain Securitized Assets		0	0	0
Amortization of Regulatory Assets and Liabilities		15.3	21.1	18.3
Total Depreciation and Amortization		527.2	446	411.6
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)		54.3	54	60.8
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		1.3	3.3	2
Revenues
TOTAL REVENUES		2,669.6	2,326.7	2,241.8
Expenses
Depreciation and Amortization		527.2	446	411.6
TOTAL EXPENSES		2,249.7	1,968.8	1,878.9
OPERATING INCOME (LOSS)		419.9	357.9	362.9
Other Income (Expense)
Allowance for Equity Funds Used During Construction		9.8	12.8	11.5
Interest Expense		(125.2)	(116.8)	(112.3)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		328.9	269.2	277.3
Income Tax Expense/Benefit		4.2	(10.6)	(7.5)
Net Income (Loss)		324.7	279.8	284.8
Accounts Receivable:
Customers		96.6	40.6
Total Accounts Receivable		205.8	121.2
TOTAL CURRENT ASSETS		571.8	439.4
Property, Plant and Equipment
Transmission		1,842.2	1,783.1
Other Property, Plant and Equipment		839.3	792.9
Construction Work in Progress		253	302.8
Total Property, Plant and Equipment		11,544.3	11,210.7
Accumulated Depreciation and Amortization		4,132.8	3,899.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,411.5	7,310.9
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		4,135.6	4,657.9
TOTAL ASSETS		12,118.9	12,408.2
Current Liabilities
Accounts Payable		173.4	174.4
Affiliated Companies		121.5	94.9
Accrued Taxes		103.2	106.5
TOTAL CURRENT LIABILITIES		1,197.1	894
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		1,702.2	2,447.9
TOTAL NONCURRENT LIABILITIES		7,913.5	8,729.5
TOTAL LIABILITIES		9,110.6	9,623.5
Equity [Abstract]
Retained Earnings		1,963.2	1,748.5
TOTAL LIABILITIES AND EQUITY		12,118.9	12,408.2
Operating Activites
Net Income (Loss)		324.7	279.8	284.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		527.2	446	411.6
Deferred Income Taxes		(45.1)	(38)	(16.2)
Allowance for Equity Funds Used During Construction		(9.8)	(12.8)	(11.5)
Change in Other Noncurrent Assets		(47.3)	(54.1)	6.1
Increase (Decrease) in Other Noncurrent Liabilities		62.4	7.5	45
Accounts Receivable, Net		(82.7)	(22.3)	14.5
Accounts Payable		37.3	42.3	(10.8)
Accrued Taxes, Net		9.4	1.6	(20.2)
Net Cash Flows from Operating Activities		720.7	733.7	776.3
Investing Activities
Net Cash Flows Used for Investing Activities		(701.5)	(633.1)	(648.9)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		(16.3)	(102.6)	(126.1)
Cash and Cash Equivalents at Beginning of Period		1.3	3.3	2
Cash and Cash Equivalents at End of Period		4.2	1.3	3.3
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		120.9	110.9	107.6
Income Taxes		10.1	29.3	42.1
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		71.9	87.8	62.8
Construction Expenditures Included in Current Liabilities as of December 31,		71.9	87.8	62.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,		0	0	33.4
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		142.7	546.7	69.5
Repayments of Long-term Debt		83.4	383.5	93.2
Net Income (Loss)		324.7	279.8	284.8
Retained Earnings		1,963.2	1,748.5
Indiana Michigan Power Co [Member] \| Retained Earnings [Member]
Other Income (Expense)
Net Income (Loss)		324.7	279.8	284.8
Operating Activites
Net Income (Loss)		324.7	279.8	284.8
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)		$ 324.7	279.8	284.8
Indiana Michigan Power Co [Member] \| Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
Indiana Michigan Power Co [Member] \| Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
Indiana Michigan Power Co [Member] \| Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
Indiana Michigan Power Co [Member] \| Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Indiana Michigan Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
Indiana Michigan Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
Indiana Michigan Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Indiana Michigan Power Co [Member] \| Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	137
Ohio Power Co [Member]
Materials and Supplies		109.5	74.1
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		293.1	301.1	275
Amortization of Certain Securitized Assets		0	0	0
Amortization of Regulatory Assets and Liabilities		1.2	2.2	1.6
Total Depreciation and Amortization		294.3	303.3	276.6
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		3
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		9.6	3	7.4	$ 3.7
Revenues
TOTAL REVENUES		3,665.1	2,899.1	2,749.1
Expenses
Depreciation and Amortization		294.3	303.3	276.6
TOTAL EXPENSES		3,251.4	2,513.9	2,345.4
OPERATING INCOME (LOSS)		413.7	385.2	403.7
Other Income (Expense)
Allowance for Equity Funds Used During Construction		13.9	10.8	12.5
Interest Expense		(119.6)	(124.4)	(117.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		331.4	288	316.6
Income Tax Expense/Benefit		44.2	34.4	45.2
Net Income (Loss)		287.8	253.6	271.4
Accounts Receivable:
Customers		119.9	71.6
Total Accounts Receivable		238.6	150
TOTAL CURRENT ASSETS		414.4	327.5
Property, Plant and Equipment
Transmission		3,198.6	2,992.8
Other Property, Plant and Equipment		1,051.4	992.9
Construction Work in Progress		474.3	365
Total Property, Plant and Equipment		11,174.6	10,421.3
Accumulated Depreciation and Amortization		2,565.3	2,458.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,609.3	7,963
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		979.4	975.3
TOTAL ASSETS		10,003.1	9,265.8
Current Liabilities
Accounts Payable		337.3	213.5
Affiliated Companies		126.1	125.4
Accrued Taxes		733.1	702.4
TOTAL CURRENT LIABILITIES		1,635.5	1,245.7
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		1,044	1,020.9
TOTAL NONCURRENT LIABILITIES		5,279.5	5,173.8
TOTAL LIABILITIES		6,915	6,419.5
Equity [Abstract]
Retained Earnings		1,929.1	1,686.3
TOTAL LIABILITIES AND EQUITY		10,003.1	9,265.8
Operating Activites
Net Income (Loss)		287.8	253.6	271.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		294.3	303.3	276.6
Deferred Income Taxes		71.5	30.7	77.2
Allowance for Equity Funds Used During Construction		(13.9)	(10.8)	(12.5)
Amortization of Deferred Property Taxes		(20)	(35.3)	(16.6)
Change in Other Noncurrent Assets		(87.1)	(40.7)	(49.4)
Increase (Decrease) in Other Noncurrent Liabilities		91.1	6.9	(66.4)
Accounts Receivable, Net		(83.7)	(11.8)	4.2
Accounts Payable		112.7	19.1	10.3
Accrued Taxes, Net		27.8	78.2	43.3
Net Cash Flows from Operating Activities		686.1	575.6	410.9
Investing Activities
Net Cash Flows Used for Investing Activities		(802.5)	(753.3)	(791)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		123	173.3	383.8
Cash and Cash Equivalents at Beginning of Period		3
Cash and Cash Equivalents at End of Period		9.6	3
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		113.4	119.5	111.2
Income Taxes		(19.7)	(7.9)	(26.9)
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		109.7	97.1	76.7
Construction Expenditures Included in Current Liabilities as of December 31,		109.7	97.1	76.7
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		0	1,037.1	347
Repayments of Long-term Debt		0.1	500.1	0.1
Income (Loss) from Equity Method Investment		0.6	0	0
Net Income (Loss)		287.8	253.6	271.4
Retained Earnings		1,929.1	1,686.3
Ohio Power Co [Member] \| Retained Earnings [Member]
Other Income (Expense)
Net Income (Loss)		287.8	253.6	271.4
Operating Activites
Net Income (Loss)		287.8	253.6	271.4
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)		$ 287.8	253.6	271.4
Ohio Power Co [Member] \| Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
Ohio Power Co [Member] \| Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
Ohio Power Co [Member] \| Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
Ohio Power Co [Member] \| Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Ohio Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
Ohio Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
Ohio Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Ohio Power Co [Member] \| Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	137
Public Service Co Of Oklahoma [Member]
Materials and Supplies		111.1	56.2
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		226.2	185.9	171.9
Amortization of Certain Securitized Assets		0	0	0
Amortization of Regulatory Assets and Liabilities		3.9	10.7	1.6
Total Depreciation and Amortization		230.1	196.6	173.5
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		1.3	2.6	1.5
Revenues
TOTAL REVENUES		1,874.7	1,474.4	1,266.1
Expenses
Depreciation and Amortization		230.1	196.6	173.5
TOTAL EXPENSES		1,693.9	1,281.5	1,090.2
OPERATING INCOME (LOSS)		180.8	192.9	175.9
Other Income (Expense)
Allowance for Equity Funds Used During Construction		1.5	2.4	4
Interest Expense		(83.8)	(62.9)	(60.3)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		118.4	145.2	128.2
Income Tax Expense/Benefit		(49.2)	4.1	5.2
Net Income (Loss)		167.6	141.1	123
Accounts Receivable:
Customers		70.1	41.5
Total Accounts Receivable		123.1	77.1
Accrued Tax Benefits		16.1	17.6
TOTAL CURRENT ASSETS		491.5	386.8
Property, Plant and Equipment
Transmission		1,164.4	1,107.7
Other Property, Plant and Equipment		469.3	437
Construction Work in Progress		219.3	156
Total Property, Plant and Equipment		7,464.2	6,508
Accumulated Depreciation and Amortization		1,837.7	1,705.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,626.5	4,802.8
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		847.9	1,209.4
TOTAL ASSETS		6,965.9	6,399
Current Liabilities
Accounts Payable		202.9	157.4
Affiliated Companies		76.7	51
Accrued Taxes		28.7	27
TOTAL CURRENT LIABILITIES		842.7	562.7
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		809.1	835.3
TOTAL NONCURRENT LIABILITIES		3,704.1	3,544.7
TOTAL LIABILITIES		4,546.8	4,107.4
Equity [Abstract]
Retained Earnings		1,218	1,095.4
TOTAL LIABILITIES AND EQUITY		6,965.9	6,399
Operating Activites
Net Income (Loss)		167.6	141.1	123
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		230.1	196.6	173.5
Deferred Income Taxes		(59.4)	113.9	17
Allowance for Equity Funds Used During Construction		(1.5)	(2.4)	(4)
Change in Other Noncurrent Assets		(35.4)	(18.3)	(17.9)
Increase (Decrease) in Other Noncurrent Liabilities		29.9	4.4	1.6
Accounts Receivable, Net		(46)	(28.7)	1.4
Accounts Payable		57.5	34.2	(29.5)
Accrued Taxes, Net		3.2	(6.5)	3.6
Net Cash Flows from Operating Activities		747.7	(433.3)	157
Investing Activities
Net Cash Flows Used for Investing Activities		(992)	(626.7)	(295.1)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		247	1,058.7	139.2
Cash and Cash Equivalents at Beginning of Period		1.3	2.6	1.5
Cash and Cash Equivalents at End of Period		4	1.3	2.6
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		79.7	57	59.1
Income Taxes		(12.5)	(102.9)	(11.8)
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		69.8	56.8	35.5
Construction Expenditures Included in Current Liabilities as of December 31,		69.8	56.8	35.5
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		499.7	1,290	0
Repayments of Long-term Debt		500.5	750.5	13.2
Net Income (Loss)		167.6	141.1	123
Retained Earnings		1,218	1,095.4
Public Service Co Of Oklahoma [Member] \| Retained Earnings [Member]
Other Income (Expense)
Net Income (Loss)		167.6	141.1	123
Operating Activites
Net Income (Loss)		167.6	141.1	123
Organization and Summary of Significant Accounting Policies (Textuals)
Net Income (Loss)		$ 167.6	141.1	123
Public Service Co Of Oklahoma [Member] \| Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
Public Service Co Of Oklahoma [Member] \| Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
Public Service Co Of Oklahoma [Member] \| Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
Public Service Co Of Oklahoma [Member] \| Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Public Service Co Of Oklahoma [Member] \| Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
Public Service Co Of Oklahoma [Member] \| Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
Public Service Co Of Oklahoma [Member] \| Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Public Service Co Of Oklahoma [Member] \| Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	137
Southwestern Electric Power Co [Member]
Materials and Supplies		92.1	81.9
Supplementary Information
Depreciation and Amortization of Property, Plant and Equipment		319.3	292.9	271.2
Amortization of Certain Securitized Assets		0	0	0
Amortization of Regulatory Assets and Liabilities		5.5	2.1	1.5
Total Depreciation and Amortization		324.8	295	272.7
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		51.2	13.2	1.6
Amounts Attributable to AEP Common Shareholders
Net Income (Loss) Attributable to Noncontrolling Interests		4.2	3.1	2.9
Net Income (Loss)		290.1	239	180.8
Revenues
TOTAL REVENUES		2,284.4	2,131.8	1,738.5
Expenses
Depreciation and Amortization		324.8	295	272.7
TOTAL EXPENSES		1,914.4	1,792.3	1,448
OPERATING INCOME (LOSS)		370	339.5	290.5
Other Income (Expense)
Allowance for Equity Funds Used During Construction		4.9	7	7.7
Interest Expense		(137.4)	(125.9)	(118.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)		267.7	238.1	190.2
Income Tax Expense/Benefit		(25.2)	(0.6)	9.4
Net Income (Loss)		294.3	242.1	183.7
Accounts Receivable:
Customers		38.8	35.8
Total Accounts Receivable		114.6	86.4
Accrued Tax Benefits		16.5	17.8
TOTAL CURRENT ASSETS		812.2	668.5
Property, Plant and Equipment
Transmission		2,479.8	2,316.9
Other Property, Plant and Equipment		804.4	764
Construction Work in Progress		369.5	240.7
Total Property, Plant and Equipment		11,789.5	10,570.4
Accumulated Depreciation and Amortization		3,527.3	3,170.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,262.2	7,400.1
Other Noncurrent Assets
TOTAL OTHER NONCURRENT ASSETS		1,304.4	1,257.1
TOTAL ASSETS		10,378.8	9,325.7
Current Liabilities
Accounts Payable		213.1	163.6
Affiliated Companies		81.7	61.4
Accrued Taxes		52.8	44.3
TOTAL CURRENT LIABILITIES		947.7	538.7
Liabilities, Noncurrent
Regulatory Liabilities and Deferred Investment Tax Credits		825.7	806.9
TOTAL NONCURRENT LIABILITIES		5,756.3	5,637.2
TOTAL LIABILITIES		6,704	6,175.9
Equity [Abstract]
Retained Earnings		2,236	2,050.9
TOTAL LIABILITIES AND EQUITY		10,378.8	9,325.7
Operating Activites
Net Income (Loss)		294.3	242.1	183.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization		324.8	295	272.7
Deferred Income Taxes		9.4	16.6	32.4
Allowance for Equity Funds Used During Construction		(4.9)	(7)	(7.7)
Change in Other Noncurrent Assets		42.9	41.9	16.1
Increase (Decrease) in Other Noncurrent Liabilities		18.3	(1.1)	25.2
Accounts Receivable, Net		(28.2)	(21.5)	7.3
Accounts Payable		34.1	22	11.1
Accrued Taxes, Net		9.8	15.4	(23.1)
Net Cash Flows from Operating Activities		586.6	96.8	356.3
Investing Activities
Net Cash Flows Used for Investing Activities		(1,085.1)	(920.7)	(392.6)
Net Cash Provided by (Used in) Financing Activities
Net Cash Flows from Financing Activities		535.7	861.9	47.9
Cash and Cash Equivalents at Beginning of Period		51.2	13.2	1.6
Cash and Cash Equivalents at End of Period		88.4	51.2	13.2
Cash Paid (Received) for:
Cash Paid for Interest, Net of Capitalized Amounts		131.2	116.5	110.7
Income Taxes		(29.1)	(28.8)	4.3
Noncash Investing and Financing Activities:
Construction in Progress Expenditures Incurred but Not yet Paid		105.6	69	46
Construction Expenditures Included in Current Liabilities as of December 31,		105.6	69	46
Organization and Summary of Significant Accounting Policies (Textuals)
Issuance of Long-term Debt		0	1,137.6	0
Repayments of Long-term Debt		6.2	381.2	21.2
Income (Loss) from Equity Method Investment		1.4	3.4	2.9
Net Income (Loss)		294.3	242.1	183.7
Retained Earnings		2,236	2,050.9
Southwestern Electric Power Co [Member] \| Retained Earnings [Member]
Amounts Attributable to AEP Common Shareholders
Net Income (Loss)		$ 290.1	239	$ 180.8
Southwestern Electric Power Co [Member] \| Pension Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		30%
Southwestern Electric Power Co [Member] \| Pension Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		54%
Southwestern Electric Power Co [Member] \| Pension Plans [Member] \| Other Investments [Member]
Target Asset Allocations
Target Asset Allocation		15%
Southwestern Electric Power Co [Member] \| Pension Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Southwestern Electric Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Equity [Member]
Target Asset Allocations
Target Asset Allocation		59%
Southwestern Electric Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation		40%
Southwestern Electric Power Co [Member] \| Other Postretirement Benefit Plans [Member] \| Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation		1%
Southwestern Electric Power Co [Member] \| Pension and Other Postretirement Benefit Plans [Member]
Supplementary Information
Securities Loaned		$ 83	$ 137
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares		1,700,000	1,300,000	1,500,000
Dilutive Securities, Effect on Basic Earnings Per Share		$ (0.02)	$ (0.01)	$ (0.02)
Revenues [Member] \| AEP Texas Inc. [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk	[1]	45%	43%	46%
Revenues [Member] \| AEP Transmission Co [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		79%	79%	78%
Revenues [Member] \| Appalachian Power Co [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		10%	10%	10%
Revenues [Member] \| Indiana Michigan Power Co [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		10%	10%	10%
Revenues [Member] \| Ohio Power Co [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		10%	10%	10%
Revenues [Member] \| Public Service Co Of Oklahoma [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		10%	10%	10%
Revenues [Member] \| Southwestern Electric Power Co [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		10%	10%	10%
Accounts Receivable [Member] \| AEP Texas Inc. [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk	[1]	42%	41%	40%
Accounts Receivable [Member] \| AEP Transmission Co [Member] \| Credit Concentration Risk
Risks and Uncertainties
Percentage of Significant Customers Concentration Risk		72%	81%	78%
Noncontrolling Interest [Member] \| Dry Lake Solar Project [Member]
Noncash Investing and Financing Activities:
Noncash Contribution of Assets by Noncontrolling Interest		$ 0	$ 35.3	$ 0
Sabine Mining Co [Member] \| Southwestern Electric Power Co [Member]
Materials and Supplies		4.2	12
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents at Beginning of Period		49.9
Property, Plant and Equipment
Other Property, Plant and Equipment		219.8	219.9
Accumulated Depreciation and Amortization		212.5	168.1
Net Cash Provided by (Used in) Financing Activities
Cash and Cash Equivalents at Beginning of Period		49.9
Cash and Cash Equivalents at End of Period		$ 84.2	$ 49.9

[1]In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica.

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions		12 Months Ended
Comprehensive Income (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		$ 184.8	$ (85.1)	$ (147.7)
Change in Fair Value Recognized in AOCI		340.3	536.8	(66.4)
Commodity
Generation and Marketing Revenues		19,639.5	16,792	14,918.5
Interest Rate
Interest Expense		1,396.1	1,199.1	1,165.7
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(537.7)	(337.9)	163.2
Income Tax (Expense) Benefit		5.4	115.5	40.5
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(424.7)	(266.9)	129
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax		(16.7)	0	0
Net Current Period Other Comprehensive Income (Loss)		(101.1)	269.9	62.6
Ending Balance in AOCI		83.7	184.8	(85.1)
Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		115.6	123.7	130.7
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(13.2)	(10.3)	(8.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(10.4)	(8.1)	(7)
Net Current Period Other Comprehensive Income (Loss)		(10.4)	(8.1)	(7)
Ending Balance in AOCI		105.2	115.6	123.7
Pension and OPEB [Member] \| Changes in Funded Status [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(73.2)	(100.7)	(163.4)
Change in Fair Value Recognized in AOCI		(155.4)	27.5	62.7
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0	0	0
Net Current Period Other Comprehensive Income (Loss)		(172.1)	27.5	62.7
Ending Balance in AOCI		(245.3)	(73.2)	(100.7)
Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(101.1)	269.9	62.6
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Commodity [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		163.7	(60.6)	(103.5)
Change in Fair Value Recognized in AOCI		477.3	488.2	(89.2)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(528.5)	(334.1)	167.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(417.5)	(263.9)	132.1
Net Current Period Other Comprehensive Income (Loss)		59.8	224.3	42.9
Ending Balance in AOCI		223.5	163.7	(60.6)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(21.3)	(47.5)	(11.5)
Change in Fair Value Recognized in AOCI	[1]	18.4	21.1	(39.9)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		4	6.5	4.9
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		3.2	5.1	3.9
Net Current Period Other Comprehensive Income (Loss)		21.6	26.2	(36)
Ending Balance in AOCI		0.3	(21.3)	(47.5)
Generation and Marketing Revenues [Member]
Commodity
Generation and Marketing Revenues		2,448.9	2,108.3	1,621
Reclassifications To Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Income Tax (Expense) Benefit		(4.4)
Reclassifications to AOCI, Current Period, before Tax, Attributable to Parent		(21.1)
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax		(16.7)
Reclassifications To Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Pension and OPEB
Income Tax (Expense) Benefit		0
Reclassifications to AOCI, Current Period, before Tax, Attributable to Parent		0
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax		0
Reclassifications To Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Pension and OPEB
Income Tax (Expense) Benefit		(4.4)
Reclassifications to AOCI, Current Period, before Tax, Attributable to Parent		(21.1)
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax		(16.7)
Reclassifications To Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Commodity [Member]
Pension and OPEB
Income Tax (Expense) Benefit		0
Reclassifications to AOCI, Current Period, before Tax, Attributable to Parent		0
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax		0
Reclassifications To Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Pension and OPEB
Income Tax (Expense) Benefit		0
Reclassifications to AOCI, Current Period, before Tax, Attributable to Parent		0
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax		0
Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	4	6.5	4.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(21.8)	(19.4)	(19.2)
Amortization of Actuarial (Gains) Losses		8.6	9.1	10.3
Income Tax (Expense) Benefit		(113)	(71)	34.2
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(21.8)	(19.4)	(19.2)
Amortization of Actuarial (Gains) Losses		8.6	9.1	10.3
Income Tax (Expense) Benefit		(2.8)	(2.2)	(1.9)
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Commodity [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		(111)	(70.2)	35.1
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Interest Rate
Interest Expense	[2]	4	6.5	4.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0.8	1.4	1
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Generation and Marketing Revenues [Member]
Commodity
Generation and Marketing Revenues	[2]	0.1	0.7	(0.4)
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Generation and Marketing Revenues [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Generation and Marketing Revenues [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Generation and Marketing Revenues [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Commodity [Member]
Commodity
Generation and Marketing Revenues	[2]	0.1	0.7	(0.4)
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Generation and Marketing Revenues [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Commodity
Generation and Marketing Revenues	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale	[2]	(528.6)	(334.8)	167.6
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Purchased Electricity for Resale [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Purchased Electricity for Resale [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Purchased Electricity for Resale [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Commodity [Member]
Commodity
Purchased Electricity for Resale	[2]	(528.6)	(334.8)	167.6
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Purchased Electricity for Resale [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Commodity
Purchased Electricity for Resale	[2]	0	0	0
Apple Blossom and Black Oak [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Change in Fair Value Recognized in AOCI		(10)	(7)	6
AEP Texas Inc. [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(6.5)	(8.9)	(12.8)
Change in Fair Value Recognized in AOCI		(3.2)	1.3	2.7
Commodity
Generation and Marketing Revenues		1,848	1,587.7	1,528
Interest Rate
Interest Expense		208.7	176.5	171.8
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.4	1.4	1.5
Income Tax (Expense) Benefit		72.6	43.1	(11.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.1	1.1	1.2
Net Current Period Other Comprehensive Income (Loss)		(2.1)	2.4	3.9
Ending Balance in AOCI		(8.6)	(6.5)	(8.9)
AEP Texas Inc. [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		5.3	5.1	4.9
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.1	0.2	0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.1	0.2	0.2
Net Current Period Other Comprehensive Income (Loss)		0.1	0.2	0.2
Ending Balance in AOCI		5.4	5.3	5.1
AEP Texas Inc. [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(10.5)	(11.7)	(14.3)
Change in Fair Value Recognized in AOCI		(3.2)	1.2	2.6
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0	0	0
Net Current Period Other Comprehensive Income (Loss)		(3.2)	1.2	2.6
Ending Balance in AOCI		(13.7)	(10.5)	(11.7)
AEP Texas Inc. [Member] \| Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(2.1)	2.4	3.9
AEP Texas Inc. [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(1.3)	(2.3)	(3.4)
Change in Fair Value Recognized in AOCI		0	0.1	0.1
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3	1.2	1.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1	0.9	1
Net Current Period Other Comprehensive Income (Loss)		1	1	1.1
Ending Balance in AOCI		(0.3)	(1.3)	(2.3)
AEP Texas Inc. [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	1.3	1.2	1.3
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains) Losses		0.2	0.3	0.3
Income Tax (Expense) Benefit		0.3	0.3	0.3
AEP Texas Inc. [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.1)	(0.1)	(0.1)
Amortization of Actuarial (Gains) Losses		0.2	0.3	0.3
Income Tax (Expense) Benefit		0	0	0
AEP Texas Inc. [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0	0	0
AEP Texas Inc. [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Interest Rate
Interest Expense	[2]	1.3	1.2	1.3
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0.3	0.3	0.3
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		24.4	7.2	5
Change in Fair Value Recognized in AOCI		(24.1)	22.3	7
Commodity
Generation and Marketing Revenues		3,520.7	3,092.9	2,809.2
Interest Rate
Interest Expense		233.9	214	217.6
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(6.4)	(6.4)	(6.1)
Income Tax (Expense) Benefit		18.2	22.1	4.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(5.1)	(5.1)	(4.8)
Net Current Period Other Comprehensive Income (Loss)		(29.2)	17.2	2.2
Ending Balance in AOCI		(4.8)	24.4	7.2
Appalachian Power Co [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.2	5.4	9.2
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(5.4)	(5.3)	(4.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(4.3)	(4.2)	(3.8)
Net Current Period Other Comprehensive Income (Loss)		(4.3)	(4.2)	(3.8)
Ending Balance in AOCI		(3.1)	1.2	5.4
Appalachian Power Co [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		15.7	2.6	(5.1)
Change in Fair Value Recognized in AOCI		(24.1)	13.1	7.7
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0	0	0
Net Current Period Other Comprehensive Income (Loss)		(24.1)	13.1	7.7
Ending Balance in AOCI		(8.4)	15.7	2.6
Appalachian Power Co [Member] \| Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(29.2)	17.2	2.2
Appalachian Power Co [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		7.5	(0.8)	0.9
Change in Fair Value Recognized in AOCI		0	9.2	(0.7)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1)	(1.1)	(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.8)	(0.9)	(1)
Net Current Period Other Comprehensive Income (Loss)		(0.8)	8.3	(1.7)
Ending Balance in AOCI		6.7	7.5	(0.8)
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	(1)	(1.1)	(1.3)
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(5.4)	(5.3)	(5.3)
Amortization of Actuarial (Gains) Losses				0.5
Income Tax (Expense) Benefit		(1.3)	(1.3)	(1.3)
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(5.4)	(5.3)	(5.3)
Amortization of Actuarial (Gains) Losses				0.5
Income Tax (Expense) Benefit		(1.1)	(1.1)	(1)
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses				0
Income Tax (Expense) Benefit		0	0	0
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Interest Rate
Interest Expense	[2]	(1)	(1.1)	(1.3)
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses				0
Income Tax (Expense) Benefit		(0.2)	(0.2)	(0.3)
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(1.3)	(7)	(11.6)
Change in Fair Value Recognized in AOCI		(0.3)	4.2	3.1
Commodity
Generation and Marketing Revenues		2,659.7	2,330.7	2,236
Interest Rate
Interest Expense		125.2	116.8	112.3
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.6	1.9	1.9
Income Tax (Expense) Benefit		4.2	(10.6)	(7.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.3	1.5	1.5
Net Current Period Other Comprehensive Income (Loss)		1	5.7	4.6
Ending Balance in AOCI		(0.3)	(1.3)	(7)
Indiana Michigan Power Co [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		4.7	4.8	4.9
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4)	(0.1)	(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3)	(0.1)	(0.1)
Net Current Period Other Comprehensive Income (Loss)		(0.3)	(0.1)	(0.1)
Ending Balance in AOCI		4.4	4.7	4.8
Indiana Michigan Power Co [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0.7	(3.5)	(6.6)
Change in Fair Value Recognized in AOCI		(0.3)	4.2	3.1
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0	0	0
Net Current Period Other Comprehensive Income (Loss)		(0.3)	4.2	3.1
Ending Balance in AOCI		0.4	0.7	(3.5)
Indiana Michigan Power Co [Member] \| Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		1	5.7	4.6
Indiana Michigan Power Co [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(6.7)	(8.3)	(9.9)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		2	2	2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.6	1.6	1.6
Net Current Period Other Comprehensive Income (Loss)		1.6	1.6	1.6
Ending Balance in AOCI		(5.1)	(6.7)	(8.3)
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	2	2	2
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.8)	(0.8)	(0.8)
Amortization of Actuarial (Gains) Losses		0.4	0.7	0.7
Income Tax (Expense) Benefit		0.3	0.4	0.4
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(0.8)	(0.8)	(0.8)
Amortization of Actuarial (Gains) Losses		0.4	0.7	0.7
Income Tax (Expense) Benefit		(0.1)	0	0
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0	0	0
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Interest Rate
Interest Expense	[2]	2	2	2
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses		0	0	0
Income Tax (Expense) Benefit		0.4	0.4	0.4
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0
Commodity
Generation and Marketing Revenues		1,875.7	1,474.3	1,263.9
Interest Rate
Interest Expense		83.8	62.9	60.3
Pension and OPEB
Income Tax (Expense) Benefit		(49.2)	4.1	5.2
Net Current Period Other Comprehensive Income (Loss)		1.3	(0.1)	(1)
Ending Balance in AOCI		1.3	0
Public Service Co Of Oklahoma [Member] \| Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		1.3	(0.1)	(1)
Public Service Co Of Oklahoma [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0	0.1	1.1
Change in Fair Value Recognized in AOCI		1.3	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0	(0.1)	(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0	(0.1)	(1)
Net Current Period Other Comprehensive Income (Loss)		1.3	(0.1)	(1)
Ending Balance in AOCI		1.3	0	0.1
Public Service Co Of Oklahoma [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Interest Rate
Interest Expense	[2]	0	(0.1)	(1.3)
Pension and OPEB
Income Tax (Expense) Benefit		0	0	(0.3)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		6.7	1.9	(1.3)
Change in Fair Value Recognized in AOCI		(9.2)	4.9	3.2
Commodity
Generation and Marketing Revenues		2,283.2	2,126	1,735.3
Interest Rate
Interest Expense		137.4	125.9	118.5
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(2.1)	(0.1)	0
Income Tax (Expense) Benefit		(25.2)	(0.6)	9.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.7)	(0.1)	0
Net Current Period Other Comprehensive Income (Loss)		(10.9)	4.8	3.2
Ending Balance in AOCI		(4.2)	6.7	1.9
Southwestern Electric Power Co [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(4.4)	(2.8)	(1.3)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(2)	(2)	(1.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.6)	(1.6)	(1.5)
Net Current Period Other Comprehensive Income (Loss)		(1.6)	(1.6)	(1.5)
Ending Balance in AOCI		(6)	(4.4)	(2.8)
Southwestern Electric Power Co [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		9.9	5	1.8
Change in Fair Value Recognized in AOCI		(9.2)	4.9	3.2
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0	0	0
Net Current Period Other Comprehensive Income (Loss)		(9.2)	4.9	3.2
Ending Balance in AOCI		0.7	9.9	5
Southwestern Electric Power Co [Member] \| Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Net Current Period Other Comprehensive Income (Loss)		(10.9)	4.8	3.2
Southwestern Electric Power Co [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.2	(0.3)	(1.8)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.1)	1.9	1.9
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.1)	1.5	1.5
Net Current Period Other Comprehensive Income (Loss)		(0.1)	1.5	1.5
Ending Balance in AOCI		1.1	1.2	(0.3)
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	(0.1)	1.9	1.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(2)	(2)	(2)
Amortization of Actuarial (Gains) Losses				0.1
Income Tax (Expense) Benefit		(0.4)	0	0
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Amortization of Deferred Costs [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		(2)	(2)	(2)
Amortization of Actuarial (Gains) Losses				0.1
Income Tax (Expense) Benefit		(0.4)	(0.4)	(0.4)
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member] \| Changes in Funded Status [Member]
Interest Rate
Interest Expense	[2]	0	0	0
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses				0
Income Tax (Expense) Benefit		0	0	0
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] \| Interest Rate [Member]
Interest Rate
Interest Expense	[2]	(0.1)	1.9	1.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)		0	0	0
Amortization of Actuarial (Gains) Losses				0
Income Tax (Expense) Benefit		$ 0	$ 0.4	$ 0.4

[1]The change in fair value includes $(10) million, $(7) million and $6 million for the years ended December 31, 2022, 2021 and 2020, respectively, related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.[2]Amounts reclassified to the referenced line item on the statements of income.

Rate Matters East Companies (De

Rate Matters East Companies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Total Property, Plant and Equipment, Net	$ 73,339.1	$ 68,304.1
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Total Property, Plant and Equipment, Net	12,379.2	11,804.3
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Total Property, Plant and Equipment, Net	7,411.5	7,310.9
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Total Property, Plant and Equipment, Net	$ 8,609.3	$ 7,963
Wheeling Power Company \| Mitchell Power Plant
Public Utilities, General Disclosures [Line Items]
Ownership Interest in Mitchell Power Plant	50%
Kentucky Power Co [Member] \| Mitchell Power Plant
Public Utilities, General Disclosures [Line Items]
Ownership Interest in Mitchell Power Plant	50%
2017-2019 Virginia Triennial Review [Member] \| Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Total Basis Point Band for Authorized Return on Equity	140%
Approved Return on Common Equity	9.20%
Proposed Previously Incurred Costs Expected to Recover	$ 37
Authorized Annual Base Rate Increase	28
Approved Rider to Recover January 2021 through September 2022	48
Expensed Remaining Closed Coal Plant	25
Approved Previously Incurred Costs to Recover	37
CCR/ELG Filings \| Mitchell Power Plant
Public Utilities, General Disclosures [Line Items]
Estimated CCR/ELG Costs	132
Estimated alternative CCR Investment	25
CCR/ELG Filings \| Kentucky Power Co [Member] \| Mitchell Power Plant
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	577
2020-2022 Virginia Triennial Review \| Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Previously Incurred Costs Deferral Below Authorized ROE Band	38
2021 and 2022 ENEC Filing \| Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2021 Requested Increase in ENEC Rates	73
2021 Projected ENEC Cost Incease	18
2021 Cumulative ENEC Under Recovery	55
2021 Approved ENEC Rate Increase	7
2021 Approved Reduction in ENEC Projected Costs	48
2022 Approved Projected ENEC Rate Increase	31
2022 Requested Increase in ENEC Rates	155
2022 Approved Overall ENEC Rate Increase	93
2022 Requested Increase in ENEC Rates Second Filing	297
2022 Recommended ENEC Under-Recovery Disallowance	83
2022 Recommended Increase in ENEC Rates	13
Current Cumulative ENEC Under Recovery	520
June 2022 Storm Costs \| Appalachian Power Co [Member] \| West Virginia
Public Utilities, General Disclosures [Line Items]
Storm Expenses to be Requested in Separate Filing	17
June 2022 Storm Costs \| Ohio Power Co [Member] \| Ohio
Public Utilities, General Disclosures [Line Items]
Storm Expenses to be Requested in Separate Filing	20
Michigan Power Supply Cost Recovery Reconciliation \| Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
ALJ Recommended Disallowance	8
Disallowance of 2020 OVEC Costs	1
Indiana Earnings Test Filings \| Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
FAC Credit to Customers	14
2022 Michigan Integrated Resource Plan Filing \| Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rockport U2 Leasehold Improvements Net Book Value	$ 17
Ohio ESP Filings [Member] \| Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Proposed ESP Return on Common Equity	10.65%
Minimum [Member] \| 2017-2019 Virginia Triennial Review [Member] \| Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	8.50%
Maximum [Member] \| 2017-2019 Virginia Triennial Review [Member] \| Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	9.90%

Rate Matters West Companies (De

Rate Matters West Companies (Details) $ in Millions	12 Months Ended
Rate Matters West Companies (Details) $ in Millions	Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Public Utilities, General Disclosures [Line Items]
Other Asset Impairment Charges	$ 48.8	$ 11.6	$ 0
Total Property, Plant and Equipment, Net	73,339.1	68,304.1
Noncurrent Regulatory Assets	4,762	4,618.8
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Total Property, Plant and Equipment, Net	11,681.6	10,635.4
Noncurrent Regulatory Assets	298.3	275.2
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Total Property, Plant and Equipment, Net	5,626.5	4,802.8
Noncurrent Regulatory Assets	653.7	1,037.4
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Other Asset Impairment Charges	0	11.6	0
Provision for Refund	(5.6)	(0.4)	$ (2)
Total Property, Plant and Equipment, Net	8,262.2	7,400.1
Noncurrent Regulatory Assets	1,042.4	$ 1,005.3
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	614
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Approved Annual Revenue Decrease	$ 14
Parent Ownership Interest In ETT	50%
AEP Share Of ETT Cumulative Revenues Subject To Review	$ 1,500
Approved interim transmission cost of service line item decrease	2
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
Estimated Reduced Annual Revenues	$ 15
2016 Texas Base Rate Case [Member] \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Equity	10%
Approved Return on Common Equity	9.60%
Requested Net Increase in Texas Annual Revenues	$ 69
Approved Net Increase in Texas Annual Revenues	50
Approved Additional Vegetation Management Expenses	2
Impairment Charge Total	19
Impairment Charge Welsh Plant, Unit 2	7
Impairment Charge Disallowed Plant Investments	12
Additional Revenues Recognized to be Surcharged to Customers	32
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management	7
2020 Texas Base Rate Case [Member] \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	$ 105
Approved Return on Common Equity	9.25%
Impairment Charge Total	$ 12
Requested Return on Equity	10.35%
Requested Net Annual Increase	$ 90
Revised Requested Annual Increase	100
Revised Requested Net Annual Increase	85
Approved Annual Revenue Increase	39
Amount of Approved Increase Related to Vegetation Management	5
Amount of Approved Increase Related to Storm Catastrophe Reserve	2
2020 Louisiana Base Rate Case [Member] \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	$ 134
Approved Return on Common Equity	9.50%
Requested Return on Equity	10.35%
Revised Requested Annual Increase	$ 95
Approved Annual Revenue Increase	27
Authorized Annual Base Rate Increase	21
Approved Rider to Recover Dolet Hils and Pirkey Costs	14
Reduction in Fuel Costs	8
2021 Arkansas Rate Case \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	$ 85
Public Utilities, Approved Equity Capital Structure, Percentage	45%
Staff Recommended Annual Rate Increase	$ 49
Requested Return on Equity	10.35%
Amount of Increase Related to Annual Depreciation Expense	$ 14
Amount of Increase Related to SPP Expenses	6
Revised Requested Annual Increase	$ 81
Staff Recommended Return on Common Equity	9.50%
Amount of Increase Related to North Central Wind Facilities	$ 41
Requested Debt Capital Structure	48.70%
Requested Equity Capital Structure	51.30%
Public Utilities, Approved Debt Capital Structure, Percentage	55%
February 2021 Severe Storm Fuel Costs \| Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Interim WACC	0.75%
Approved Carrying Charge	0.75%
Proceeds For Securitzation Bonds	$ 687
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets	$ 329
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Louisiana Jurisdiction [Member]
Public Utilities, General Disclosures [Line Items]
Interim WACC	3.25%
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Louisiana Jurisdiction [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets	$ 122
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Arkansas
Public Utilities, General Disclosures [Line Items]
Requested Weighted Average Cost of Capital	6.05%
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Arkansas \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets	$ 75
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Texas
Public Utilities, General Disclosures [Line Items]
Requested Weighted Average Cost of Capital	7.18%
Approved Carrying Charge	1.65%
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Texas \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets	$ 132
2021 Louisiana Storm Cost Filing \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Deferred Storm Costs	145
2022 Oklahoma Base Rate Case [Member] \| Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Increase Related to Annual Depreciation Expense	$ 47
Requested Debt Capital Structure	45.40%
Requested Equity Capital Structure	54.60%
Requested Net Increase in Oklahoma Annual Increase	$ 173
Amount of Increase Related to Annual Amortization Expense	$ 16
2022 Oklahoma Base Rate Case [Member] \| Public Service Co Of Oklahoma [Member] \| Rock Falls [Member]
Public Utilities, General Disclosures [Line Items]
WindGenerationMWs \| MW	154
2022 Oklahoma Base Rate Case [Member] \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Equity	10.40%
Minimum [Member] \| 2012 Texas Base Rate Case [Member] \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Turk AFUDC Disallowance	$ 80
Estimated Turk AFUDC Refunds	0
Maximum [Member] \| 2012 Texas Base Rate Case [Member] \| Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Turk AFUDC Disallowance	90
Estimated Turk AFUDC Refunds	$ 185

Rate Matters FERC (Details)

Rate Matters FERC (Details) $ in Millions	12 Months Ended
Rate Matters FERC (Details) $ in Millions	Dec. 31, 2022 USD ($)
Public Utilities, General Disclosures [Line Items]
AEP Share of Independence Energy Connection Capital Costs	$ 87
Estimated PreTax Income Reduction	$ 20
Ohio Power Co [Member] \| Ohio Transmission Company [Member]
Public Utilities, General Disclosures [Line Items]
Basis Point RTO Incentive	50%

Effects of Regulation (Details)

Effects of Regulation (Details) - USD ($) $ in Millions		12 Months Ended
Effects of Regulation (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Regulated Generating Unit to be Retired
Net Investment		$ 73,339.1	$ 68,304.1
Materials and Supplies		915.1	701.8
Annual Depreciation		3,072.8	2,717.1	$ 2,487.5
Regulatory Assets
Current Regulatory Assets		1,310	656
Noncurrent Regulatory Assets		4,762	4,618.8
Regulatory Liabilities
Current Regulatory Liabilities		1.4	1.5
Noncurrent Regulatory Liabilities		8,115.6	8,834.4
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[1],[2],[3],[4],[5],[6],[7]	100.3	138.6
Secured Debt		487.8	603.5
Accumulated Depreciation and Amortization		23,682.3	21,920.9
Asset Impairments and Other Related Charges		48.8	11.6	0
AEP Texas Inc. [Member]
Regulated Generating Unit to be Retired
Net Investment		11,681.6	10,635.4
Materials and Supplies		138.8	73.9
Annual Depreciation		363.5	327.2	364.2
Regulatory Assets
Noncurrent Regulatory Assets		298.3	275.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,259.6	1,242
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[2],[3],[7]	0	0
Secured Debt		314.4	404.7
Accumulated Depreciation and Amortization		1,760.7	1,644.1
AEP Transmission Co [Member]
Regulated Generating Unit to be Retired
Net Investment		13,339.9	12,101
Materials and Supplies		10.7	9.3
Annual Depreciation		346.2	297.3	249
Regulatory Assets
Noncurrent Regulatory Assets		7.2	8.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities		723.3	651.7
Effects of Regulation Textuals [Abstract]
Accumulated Depreciation and Amortization		1,027	784.1
Appalachian Power Co [Member]
Regulated Generating Unit to be Retired
Net Investment		12,379.2	11,804.3
Materials and Supplies		130.6	109.8
Annual Depreciation		576.1	547	507.8
Regulatory Assets
Current Regulatory Assets		473.1	201.3
Noncurrent Regulatory Assets		1,058.6	757.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,143.6	1,238.8
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[2],[3],[7]	17	84.7
Secured Debt		173.3	198.8
Accumulated Depreciation and Amortization		5,402	5,051.8
Asset Impairments and Other Related Charges		24.9	0	0
Indiana Michigan Power Co [Member]
Regulated Generating Unit to be Retired
Net Investment		7,411.5	7,310.9
Materials and Supplies		188.1	175.2
Annual Depreciation		511.9	424.9	393.3
Regulatory Assets
Current Regulatory Assets		47.1	6.4
Noncurrent Regulatory Assets		459.6	410.9
Regulatory Liabilities
Current Regulatory Liabilities		0	1.5
Noncurrent Regulatory Liabilities		1,702.2	2,447.9
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[2],[3],[4],[7]	7.7	59.4
Accumulated Depreciation and Amortization		4,132.8	3,899.8
Ohio Power Co [Member]
Regulated Generating Unit to be Retired
Net Investment		8,609.3	7,963
Materials and Supplies		109.5	74.1
Annual Depreciation		293.1	301.1	275
Regulatory Assets
Current Regulatory Assets		3.8	0
Noncurrent Regulatory Assets		327.3	293
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,044	1,020.9
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[2],[7]	0	0
Accumulated Depreciation and Amortization		2,565.3	2,458.3
Public Service Co Of Oklahoma [Member]
Regulated Generating Unit to be Retired
Net Investment		5,626.5	4,802.8
Materials and Supplies		111.1	56.2
Annual Depreciation		226.2	185.9	171.9
Regulatory Assets
Current Regulatory Assets		178.7	194.6
Noncurrent Regulatory Assets		653.7	1,037.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		809.1	835.3
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[2],[3],[6],[7]	1.9	0
Accumulated Depreciation and Amortization		1,837.7	1,705.2
Southwestern Electric Power Co [Member]
Regulated Generating Unit to be Retired
Net Investment		8,262.2	7,400.1
Materials and Supplies		92.1	81.9
Annual Depreciation		319.3	292.9	271.2
Regulatory Assets
Current Regulatory Assets		353	143.9
Noncurrent Regulatory Assets		1,042.4	1,005.3
Regulatory Liabilities
Current Regulatory Liabilities		1.4	0
Noncurrent Regulatory Liabilities		825.7	806.9
Effects of Regulation Textuals [Abstract]
Revisions in Cash Flow Estimates	[1],[2],[3],[6],[7]	56.7	2.5
Accumulated Depreciation and Amortization		3,527.3	3,170.3
Asset Impairments and Other Related Charges		0	11.6	$ 0
Net Under-Recovered Fuel Costs		257
Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		7,961.8	8,569.9
Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,244.8	1,229
Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,113.1	1,234.3
Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,789.9	2,447.9
Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,043.8	1,020.7
Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		757.8	779.1
Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		818.7	806.9
Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		153.8	264.5
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		14.8	13
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		8.7	8.7
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		30.5	4.5
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		(87.7)	0
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.2
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		51.3	56.2
Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		7	0
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		5,983.4	6,057.2
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,202.7	1,194.8
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		714.6	643
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,005.1	1,136.5
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		365.5	384.2
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		918.4	948.2
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		696.4	724
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		811	793.9
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		149.7	262.2
Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		13	13
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,978.4	2,512.7
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		42.1	34.2
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		108	97.8
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,424.4	2,063.7
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		125.4	72.5
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		61.4	55.1
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		7.7	13
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		4.1	2.3
Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.8	0
Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		882.1	1,090.9
Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		67	41.2
Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		144.5	105.1
Regulatory Assets Pending Final Regulatory Approval [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		23.7	3.7
Regulatory Assets Pending Final Regulatory Approval [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		33.8	3.8
Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		510.2	817.9
Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3,879.9	3,527.9
Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		231.3	234
Regulatory Assets Approved for Recovery [Member] \| AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		7.2	8.5
Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		914.1	652.5
Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		435.9	407.2
Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		293.5	289.2
Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		628.1	1,023.2
Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		532.2	187.4
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		355.6	695.6
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		17.6	0
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		7	6.8
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.1	0.1
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		330.9	641.2
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,858.6	1,841.8
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		17.5	35.4
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		299.3	110.4
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		270.6	303.3
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		34.9	56.9
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		552.8	981.5
Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		321.8	29.9
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		526.5	395.3
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		49.4	41.2
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		137.5	98.3
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		23.6	3.6
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		25.6	14.2
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		179.3	176.7
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		2,021.3	1,686.1
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		213.8	198.6
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		614.8	542.1
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		165.3	103.9
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		258.6	232.3
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		75.3	41.7
Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		210.4	157.5
Northeastern Plant, Unit 3 [Member] \| Generating Units Probable of Abandonment [Member] \| Public Service Co Of Oklahoma [Member]
Regulated Generating Unit to be Retired
Net Investment		136.3
Accelerated Depreciation Regulatory Asset		145.8
Cost of Removal Regulatory Liability	[8]	$ 20.2
Expected Retirement Date	[9]	2026
Annual Depreciation	[10]	$ 14.9
Dolet Hills Power Station [Member] \| Southwestern Electric Power Co [Member]
Effects of Regulation Textuals [Abstract]
Recommended Dolet Hills Fuel Disallowance		72
Pirkey Power Plant [Member] \| Generating Units Probable of Abandonment [Member] \| Southwestern Electric Power Co [Member]
Regulated Generating Unit to be Retired
Net Investment		35.1
Accelerated Depreciation Regulatory Asset		179.5
Cost of Removal Regulatory Liability		$ 39.8
Expected Retirement Date	[11]	2023
Annual Depreciation	[10]	$ 11.7
Welsh Plant, Units 1 and 3 [Member] \| Generating Units Probable of Abandonment [Member] \| Southwestern Electric Power Co [Member]
Regulated Generating Unit to be Retired
Net Investment		416.8
Accelerated Depreciation Regulatory Asset		85.6
Cost of Removal Regulatory Liability	[12]	$ 58.3
Expected Retirement Date	[13]	2028
Annual Depreciation	[10]	$ 37.9
Deferred Fuel Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 1.4	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities	[14]	$ 1.4	0
Deferred Fuel Costs [Member] \| Regulatory Liabilities Currently Not Paying Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		0	1.5
Deferred Fuel Costs [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Indiana Michigan Power Co [Member] \| Indiana
Regulatory Liabilities
Current Regulatory Liabilities		0	1.5
Deferred Fuel Costs [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 32.2	15.2
Remaining Refund Period		10 years
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Earning Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 625.7	409.4
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 180.7	127.2
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Indiana Michigan Power Co [Member] \| Michigan
Regulatory Assets
Current Regulatory Assets		$ 9	6.4
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Current Regulatory Assets		$ 178.7	194.6
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets	[15]	$ 257.2	81.2
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 588.5	183.9
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 292.4	74.1
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Indiana Michigan Power Co [Member] \| Indiana
Regulatory Assets
Current Regulatory Assets		$ 38.1	0
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Ohio Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 3.8	0
Remaining Recovery Period		1 year
Dolet Hills Power Station Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[16]	$ 9.7	72.3
Dolet Hills Power Station Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[17]	9.7	72.3
Kentucky Deferred Purchase Power Expenses [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	47.5
Kentucky Deferred Purchase Power Expenses [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 53	0
Remaining Recovery Period		5 years
Plant Retirement Costs - Unrecovered Plant, Louisiana [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	35.2
Plant Retirement Costs - Unrecovered Plant, Louisiana [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	35.2
Pirkey Power Plant Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		116.5	87
Pirkey Power Plant Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		116.5	87
Pirkey Power Plant Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Louisiana Jurisdiction [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 63	0
Remaining Recovery Period		10 years
Pirkey Power Plant Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member] \| Louisiana Jurisdiction [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 63	0
Remaining Recovery Period		10 years
Welsh Plant, Units 1 and 3 Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 85.6	45.9
Welsh Plant, Units 1 and 3 Accelerated Depreciation [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		85.6	45.9
COVID-19 - Virginia [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		7	6.8
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		27.2	9.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.1	0.1
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		2.5	2.4
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		55.6	56
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		13.4	9.5
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.1	3.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		2	3.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.1	0.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		16	18.4
Storm Related Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.4	17.4
Remaining Recovery Period		2 years
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 407.1	298.3
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		26.7	22.4
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		72.6	53.7
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		21.6	0
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		33.8	3.8
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		25.5	13.9
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		151.5	148
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.9	25.4
Remaining Recovery Period		2 years
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.5	12.8
Remaining Recovery Period		2 years
Storm Related Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.4	12.6
Remaining Recovery Period		2 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 110.6	110.2
Remaining Recovery Period		20 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.9	25.9
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		25.9	25.9
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 308.5	297.9
Remaining Recovery Period		20 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 303.1	293.1
Remaining Recovery Period		15 years
Vegetation Management Program [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.2	5.2
Vegetation Management Program [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.1	17.4
Remaining Recovery Period		3 years
Plant Retirement Costs - Unrecovered Plant [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[18]	$ 689.9	715.4
Remaining Recovery Period		24 years
Plant Retirement Costs - Unrecovered Plant [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 75.6	110
Remaining Recovery Period		21 years
Plant Retirement Costs - Unrecovered Plant [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 147	170.8
Remaining Recovery Period		6 years
Plant Retirement Costs - Unrecovered Plant [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[19]	$ 240.6	227.6
Remaining Recovery Period		24 years
Plant Retirement Costs - Unrecovered Plant, Arkansas [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 13.1	13.7
Remaining Recovery Period		20 years
Plant Retirement Costs - Unrecovered Plant, Arkansas [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 21.1	0
Remaining Recovery Period		5 years
Plant Retirement Costs - Unrecovered Plant, Arkansas [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 21.1	0
Remaining Recovery Period		5 years
Plant Retirement Costs - Unrecovered Plant, Texas [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 51.7	51.9
Remaining Recovery Period		24 years
Plant Retirement Costs - Unrecovered Plant, Texas [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 51.7	51.9
Remaining Recovery Period		24 years
Meter Replacement Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 34.2	44.9
Remaining Recovery Period		5 years
Meter Replacement Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 16.1	22.7
Remaining Recovery Period		4 years
Meter Replacement Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.1	22.2
Remaining Recovery Period		5 years
Ohio Distribution Decoupling [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.5	41.6
Remaining Recovery Period		2 years
Ohio Distribution Decoupling [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.5	41.6
Remaining Recovery Period		2 years
Ohio Basic Transmission Cost Rider [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 14.3	5.2
Remaining Recovery Period		2 years
Environmental Controls Projects [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.9	36.2
Remaining Recovery Period		18 years
Environmental Controls Projects [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 23.9	25.2
Remaining Recovery Period		18 years
Environmental Controls Projects [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10	11
Remaining Recovery Period		10 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 56.6	66.6
Remaining Recovery Period		6 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 56.6	66.6
Remaining Recovery Period		6 years
Cook Plant Uprate Project [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.3	27.7
Remaining Recovery Period		11 years
Cook Plant Uprate Project [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.3	27.7
Remaining Recovery Period		11 years
Advanced Metering System [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	10.6
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		102.9	119.9
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.4	2.1
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.4	0.4
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		11.9	6
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		9.1	9.8
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		6.8	5.2
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		118.3	119.2
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		4.3	4.3
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		16	14.2
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		22.9	18.2
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		11	14.4
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		20.1	18.8
Other Regulatory Assets Approved for Recovery [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		32.5	18.8
Vegetation Management [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.8	29.3
Remaining Recovery Period		3 years
Asset Retirement Obligation - Louisiana [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.8	10.3
Deferred Cook Plant Life Cycle Management Project Costs [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.1	13.1
Remaining Recovery Period		12 years
Cook Plant Study Costs - Indiana [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.7	9.4
Remaining Recovery Period		13 years
Cook Plant Turbine [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9	9.7
Remaining Recovery Period		16 years
Pension Costs [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	27.6
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 975.4	689.3
Remaining Recovery Period		12 years
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 173.2	119
Remaining Recovery Period		12 years
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 108.3	62.7
Remaining Recovery Period		12 years
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 26.9	0
Remaining Recovery Period		12 years
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 142.7	83.3
Remaining Recovery Period		12 years
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 55.2	22.9
Remaining Recovery Period		12 years
Pension Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 96.2	73.8
Remaining Recovery Period		12 years
Unamortized Loss on Reacquired Debt [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 104.1	111.6
Remaining Recovery Period		26 years
Unamortized Loss on Reacquired Debt [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 74.4	78.2
Remaining Recovery Period		23 years
Unamortized Loss on Reacquired Debt [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.9	14.2
Remaining Recovery Period		26 years
Peak Demand Reduction/Energy Efficiency [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.9	14.5
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.8	17.8
Remaining Recovery Period		4 years
Unrealized Loss on Forward Commitments [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 40.1	100.8
Remaining Recovery Period		10 years
Unrealized Loss on Forward Commitments [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 40	92.1
Remaining Recovery Period		10 years
Virginia Transmission Rate Adjustment Clause [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.7	37.2
Remaining Recovery Period		2 years
Virginia Transmission Rate Adjustment Clause [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.7	37.2
Remaining Recovery Period		2 years
Vegetation Management Program - West Virginia [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 13.7	11.9
Remaining Recovery Period		2 years
Cook Nuclear Plant Refueling Outage Levelization [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 81.2	32
Remaining Recovery Period		3 years
Cook Nuclear Plant Refueling Outage Levelization [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 81.2	32
Remaining Recovery Period		3 years
PJM/SPP Annual Formula Rate True Up [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 21.8	18
Remaining Recovery Period		2 years
PJM/SPP Annual Formula Rate True Up [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Transmission Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.2	8.5
Remaining Recovery Period		2 years
Postemployment Benefits [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 32.1	32.5
Remaining Recovery Period		3 years
Postemployment Benefits [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 13.7	13.3
Remaining Recovery Period		3 years
Postemployment Benefits [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.7	9
Remaining Recovery Period		3 years
Postemployment Benefits [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.2	6.2
Remaining Recovery Period		3 years
OVEC Purchased Power [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 47.1	14.8
Remaining Refund Period		2 years
OVEC Purchased Power [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 47.1	14.8
Remaining Refund Period		2 years
Fuel and Purchased Power Adjustment Rider [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 76.3	40.8
Remaining Recovery Period		2 years
PJM Costs and Off-system Sales Margin Sharing - Indiana [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 34.2	0
Remaining Refund Period		2 years
PJM Costs and Off-system Sales Margin Sharing - Indiana [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 34.2	0
Remaining Refund Period		2 years
PJM Costs and Off-system Sales Margin Sharing - Indiana [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	15.1
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		4.1	2.3
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.8	0
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.2
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 277	468
Remaining Refund Period		6 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 16	26
Remaining Refund Period		6 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 19	84
Remaining Refund Period		6 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 42	90
Remaining Refund Period		6 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 162	191
Remaining Refund Period		6 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 21	46
Remaining Refund Period		2 years
Excess ADIT that is Not Subject to Rate Normalization Requirements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 7	7
Remaining Refund Period		1 year
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[20]	$ 3,392.4	3,229.9
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[21]	766.8	744.7
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[22]	358.8	271.4
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[23]	713.5	703.3
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[24]	170.7	179.7
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[25]	466.5	467.6
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[26]	316.3	300.2
Asset Removal Costs [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[27]	481.2	461.3
Deferred Investment Tax Credits [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0.3	0.3
Remaining Refund Period		31 years
Deferred Investment Tax Credits [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 237.3	248.5
Remaining Refund Period		34 years
Deferred Investment Tax Credits [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 17.4	22.4
Remaining Refund Period		28 years
Deferred Investment Tax Credits [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 48.2	50.8
Remaining Refund Period		22 years
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 9.5	16.2
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		4.3	4.8
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		3	7
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		2.2	2.4
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		86.9	62.6
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		12.7	7.9
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		11	6.6
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		8.5	13.9
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		7.8	0.4
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		13.2	4.3
Other Regulatory Liabilities Approved for Payment [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		7.7	13
Excess Nuclear Decommissioning Funding [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[28]	1,318.5	1,939.7
Excess Nuclear Decommissioning Funding [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[29]	1,318.5	1,939.7
PJM Transmission Enhancement Refund [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 34.1	45.5
Remaining Refund Period		3 years
PJM Transmission Enhancement Refund [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 9.8	13
Remaining Refund Period		3 years
PJM Transmission Enhancement Refund [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 14.7	19.6
Remaining Refund Period		3 years
Transition and Restoration Charges [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 29.4	26.3
Remaining Refund Period		7 years
Transition and Restoration Charges [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 29.4	26.3
Remaining Refund Period		7 years
2017-2019 Virginia Triennial Revenue Provision [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 39.1	41.6
Remaining Refund Period		26 years
2017-2019 Virginia Triennial Revenue Provision [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 39.1	41.6
Remaining Refund Period		26 years
2017-2019 Virginia Triennial Revenue Provision [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 30.1	0
Remaining Recovery Period		2 years
2017-2019 Virginia Triennial Revenue Provision [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 30.1	0
Remaining Recovery Period		2 years
Spent Nuclear Fuel [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[28]	$ 45.8	49.5
Spent Nuclear Fuel [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[29]	45.8	49.5
Peak Demand Reduction/Energy Efficiency [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 28.6	28.6
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 23.6	22.5
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 41.7	40.8
Remaining Recovery Period		4 years
Peak Demand Reduction/Energy Efficiency [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.3	2.8
Remaining Recovery Period		2 years
Ohio Enhanced Service Reliability Plan [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.3	9.5
Remaining Recovery Period		2 years
Ohio Enhanced Service Reliability Plan [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.3	9.5
Remaining Recovery Period		2 years
Smart Grid Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.4	19.3
Remaining Recovery Period		2 years
Smart Grid Costs [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.4	19.3
Remaining Recovery Period		2 years
Dolet Hills Generating Station and Related Fuel Operations \| Southwestern Electric Power Co [Member]
Effects of Regulation Textuals [Abstract]
Share of Net Investment in Dolet Hills Power Station		$ 112
Amount of Dolet Hills Fuel Costs Approved to Recover		20
Approved Deferral of Dolet Hills Fuel Costs		32
Pirkey Power Plant and Related Fuel Operations \| Southwestern Electric Power Co [Member]
Effects of Regulation Textuals [Abstract]
Share of Net Investment in Pirkey Power Plant		215
Pirkey Power Plant and Sabine Unbilled Fixed Costs		43
Dolet Hills Power Station [Member] \| Southwestern Electric Power Co [Member] \| TEXAS
Effects of Regulation Textuals [Abstract]
Asset Impairments and Other Related Charges		12
Dolet Hills Power Station [Member] \| Southwestern Electric Power Co [Member] \| Arkansas
Effects of Regulation Textuals [Abstract]
Asset Impairments and Other Related Charges		2
Unrealized Gain on Forward Commitments [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 45.2	40.4
Remaining Refund Period		2 years
Unrealized Gain on Forward Commitments [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 34.5	28.2
Remaining Refund Period		2 years
Welsh Plant Unit 2 \| Southwestern Electric Power Co [Member]
Effects of Regulation Textuals [Abstract]
Impairment Charge Welsh Plant, Unit 2		$ 7
February 2021 Severe Storm Fuel Costs
Effects of Regulation Textuals [Abstract]
Proceeds For Securitzation Bonds		687
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member]
Regulatory Assets
Current Regulatory Assets	[30]	$ 95.8	62.7
Remaining Recovery Period		1 year
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets	[31]	$ 95.8	62.7
Remaining Recovery Period		1 year
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 84.6	367.5
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[31]	84.6	367.5
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[32]	$ 148.6	679.3
Remaining Recovery Period		5 years
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[33]	$ 0	679.3
February 2021 Severe Storm Fuel Costs \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[31]	$ 148.6	0
Remaining Recovery Period		5 years
Dolet Hills Power Station Fuel Costs - Louisiana \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 32	30.9
Dolet Hills Power Station Fuel Costs - Louisiana \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		32	30.9
Texas Transmission Cost Recovery Factor \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.8	30.6
Remaining Recovery Period		2 years
Texas Transmission Cost Recovery Factor \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.8	30.6
Remaining Recovery Period		2 years
Texas Retail Electric Provider Bad Debt Expense \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.1	4.1
Environmental Compliance Costs \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.3	13.7
Remaining Recovery Period		2 years
Environmental Cost Rider - Indiana \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	10.6
Ohio Economic Development Rider \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.1	10.1
Remaining Recovery Period		2 years
PJM Load Service Entity Formula Rate True-Up \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	7.5
Dolet Hills Power Station Fuel Costs - Arkansas \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.9	13
Remaining Recovery Period		4 years
2020-2022 Virginia Triennial Revenue Provision [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 37.9	15.1
2020-2022 Virginia Triennial Revenue Provision [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		37.9	15.1
Long-term Under-recovered Fuel Costs - Oklahoma [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 252.7	0
Remaining Recovery Period		2 years
Long-term Under-recovered Fuel Costs - Oklahoma [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 252.7	0
Remaining Recovery Period		2 years
Long-term Under-recovered Fuel Costs - Virginia [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 223.3	0
Remaining Recovery Period		2 years
Long-term Under-recovered Fuel Costs - Virginia [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 223.3	0
Remaining Recovery Period		2 years
Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Louisiana Jurisdiction [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 45.1	0
Remaining Recovery Period		10 years
Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member] \| Louisiana Jurisdiction [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 45.1	0
Remaining Recovery Period		10 years
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[34],[35]	$ 2,504.5	2,792
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[36],[37]	431.6	445.3
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[38],[39]	355.8	371.6
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[40],[41]	291.3	432.9
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[42],[43]	168.6	182.6
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[44],[45]	451.9	480.6
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[46],[47]	380.1	423.8
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[48],[49]	327.6	330.2
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[34]	149.7	262.2
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Texas Inc. [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[36]	13	13
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| AEP Transmission Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[38]	8.7	8.7
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[40]	30.5	4.5
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[42],[50]	(87.7)	0
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[46]	51.3	56.2
Income Taxes, Net [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Pending Final Regulatory Determination [Member] \| Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[48]	7	0
Rockport Plant, Unit 2 Accelerated Depreciation for Leasehold Improvements [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 53.8	4.2
Remaining Refund Period		6 years
Renewable Energy Surcharge - Michigan [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 23.2	14.9
Remaining Refund Period		2 years
Renewable Energy Surcharge - Michigan [Member] \| Regulatory Liabilities Currently Paying a Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 23.2	14.9
Remaining Refund Period		2 years
Over-recovered Fuel Costs - Ohio [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 32.2	15.2
Remaining Refund Period		10 years
Texas Mobile Generation Lease Payments [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member] \| AEP Texas Inc. [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 17.6	0
Virginia Clean Economy Act [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 16.7	0
Remaining Recovery Period		2 years
Over-recovered Deferred Wind Costs - Virginia [Member] \| Regulatory Liabilities Currently Not Paying Return [Member] \| Regulatory Liabilities Approved for Payment [Member] \| Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 13.6	8.4
Remaining Refund Period		2 years
Plant Retirement Costs - Unrecovered Plant, Welsh Plant, Unit 2 [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Approved for Recovery [Member] \| Southwestern Electric Power Co [Member] \| Louisiana Jurisdiction [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 35.2	$ 0
Remaining Recovery Period		10 years
February 2021 Severe Storm Fuel Costs \| Public Service Co Of Oklahoma [Member]
Effects of Regulation Textuals [Abstract]
Proceeds For Securitzation Bonds		$ 687
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		329
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Arkansas \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		75
February 2021 Severe Storm Fuel Costs \| Southwestern Electric Power Co [Member] \| Louisiana Jurisdiction [Member] \| Regulatory Assets Currently Earning Return [Member] \| Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 122

[1]Includes ARO related to Sabine and DHLC.[2]Includes ARO related to asbestos removal.[3]Includes ARO related to ash disposal facilities.[4]Includes ARO related to nuclear decommissioning costs for the Cook Plant of $2 billion and $1.93 billion as of December 31, 2022 and 2021, respectively.[5]Includes ARO related to solar farms.[6]Includes ARO related to wind farms.[7]Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.[8]Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.[9]Northeastern Plant, Unit 3 is currently being recovered through 2040.[10]Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.[11]Pirkey Plant is currently being recovered through 2032 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.[12]Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.[13]Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.[14]2022 amount includes Louisiana jurisdiction.[15]2022 amount includes Arkansas and Texas jurisdictions. 2021 amount includes Arkansas, Louisiana and Texas jurisdictions.[16]2022 amount includes the FERC jurisdiction. 2021 amounts include Arkansas, Louisiana and FERC jurisdictions.[17]2022 amount includes the FERC jurisdiction. 2021 amounts include Arkansas, Louisiana and FERC jurisdictions.[18]Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.[19]Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.[20]Relieved as removal costs are incurred.[21]Relieved as removal costs are incurred.[22]Relieved as removal costs are incurred.[23]Relieved as removal costs are incurred.[24]Relieved as removal costs are incurred.[25]Relieved as removal costs are incurred.[26]Relieved as removal costs are incurred.[27]Relieved as removal costs are incurred.[28]Relieved when plant is decommissioned.[29]Relieved when plant is decommissioned.[30]In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.[31]In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.[32]In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.[33]In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.[34]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[35]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $277 million and $468 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.[36]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[37]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets.[38]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[39]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $16 million and $26 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.[40]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[41]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $19 million and $84 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.[42]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[43]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $42 million and $90 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.[44]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[45]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $162 million and $191 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.[46]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[47]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $21 million and $46 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 2 years.[48]Predominately pays a return due to the inclusion of Excess ADIT in rate base.[49]Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $7 million and $7 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 1 year.[50]Represents an income tax related regulatory asset, which is presented within net regulatory liabilities on the balance sheet.

Commitments, Guarantees and C_3

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Contractual Commitments
Less than 1 year		$ 1,667.6
For 2-3 years		2,089.5
For 4-5 years		694.5
After 5 years		822.5
Total Contractual Commitments		5,274.1
Commitments, Guarantees and Contingencies (Textuals)
Revolving Credit Facilities		5,000
Disposal, Assessed Fees and Related Interest	[1]	285.6	$ 281.3
Rockport Plant, Unit 2 Acquisition Price		$ 116
Regulatory Assets Currently Not Earning Return [Member] \| Unamortized Loss on Reacquired Debt [Member] \| Regulatory Assets Approved for Recovery [Member]
Commitments, Guarantees and Contingencies (Textuals)
Remaining Recovery Period		26 years
Rockport Plant, Unit 2 [Member]
Commitments, Guarantees and Contingencies (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		100%
AEP Wind Holdings LLC [Member] \| Generation and Marketing [Member]
Commitments, Guarantees and Contingencies (Textuals)
Maximum Potential Amount of Future Payments Associated with Guarantee		$ 59
Guarantor Obligations, Current Carrying Value		5
Guarantor Obligations, Current Carrying Value, Contingent Portion		1
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		287.4
Commitments, Guarantees and Contingencies (Textuals)
Letters of Credit Limit		1,200
Uncommitted Facility		400
Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	1,499.8
For 2-3 years	[2]	1,711.8
For 4-5 years	[2]	345.4
After 5 years	[2]	252
Total Contractual Commitments	[2]	3,809
Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		167.8
For 2-3 years		377.7
For 4-5 years		349.1
After 5 years		570.5
Total Contractual Commitments		1,465.1
AEP Texas Inc. [Member] \| Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		1.8
Appalachian Power Co [Member]
Contractual Commitments
Less than 1 year		881.4
For 2-3 years		1,185.6
For 4-5 years		343.1
After 5 years		136.2
Total Contractual Commitments		$ 2,546.3
Appalachian Power Co [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Unamortized Loss on Reacquired Debt [Member] \| Regulatory Assets Approved for Recovery [Member]
Commitments, Guarantees and Contingencies (Textuals)
Remaining Recovery Period		23 years
Appalachian Power Co [Member] \| Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	$ 840.9
For 2-3 years	[2]	1,102.9
For 4-5 years	[2]	263.2
After 5 years	[2]	9.2
Total Contractual Commitments	[2]	2,216.2
Appalachian Power Co [Member] \| Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		40.5
For 2-3 years		82.7
For 4-5 years		79.9
After 5 years		127
Total Contractual Commitments		330.1
Indiana Michigan Power Co [Member]
Contractual Commitments
Less than 1 year		341.8
For 2-3 years		525.2
For 4-5 years		327.1
After 5 years		499.2
Total Contractual Commitments		1,693.3
Commitments, Guarantees and Contingencies (Textuals)
Disposal, Assessed Fees and Related Interest	[1]	285.6	281.3
Rockport Plant, Unit 2 Acquisition Price		$ 116
Indiana Michigan Power Co [Member] \| Regulatory Assets Currently Not Earning Return [Member] \| Unamortized Loss on Reacquired Debt [Member] \| Regulatory Assets Approved for Recovery [Member]
Commitments, Guarantees and Contingencies (Textuals)
Remaining Recovery Period		26 years
Indiana Michigan Power Co [Member] \| Rockport Plant, Unit 2 [Member]
Commitments, Guarantees and Contingencies (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
Indiana Michigan Power Co [Member] \| Rockport Plant Litigation [Member] \| Rockport Plant, Unit 2 [Member]
Commitments, Guarantees and Contingencies (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
Indiana Michigan Power Co [Member] \| Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	$ 200.9
For 2-3 years	[2]	235.2
For 4-5 years	[2]	53.3
After 5 years	[2]	222.4
Total Contractual Commitments	[2]	711.8
Indiana Michigan Power Co [Member] \| Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		140.9
For 2-3 years		290
For 4-5 years		273.8
After 5 years		276.8
Total Contractual Commitments		981.5
Ohio Power Co [Member] \| Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		34.4
For 2-3 years		66.5
For 4-5 years		63.7
After 5 years		169.8
Total Contractual Commitments		334.4
Public Service Co Of Oklahoma [Member]
Contractual Commitments
Less than 1 year		82.9
For 2-3 years		130.8
For 4-5 years		122.8
After 5 years		91.4
Total Contractual Commitments		427.9
Public Service Co Of Oklahoma [Member] \| Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	35.8
For 2-3 years	[2]	14.5
For 4-5 years	[2]	0
After 5 years	[2]	0
Total Contractual Commitments	[2]	50.3
Public Service Co Of Oklahoma [Member] \| Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		47.1
For 2-3 years		116.3
For 4-5 years		122.8
After 5 years		91.4
Total Contractual Commitments		377.6
Southwestern Electric Power Co [Member]
Contractual Commitments
Less than 1 year		143.8
For 2-3 years		116.3
For 4-5 years		13.2
After 5 years		0
Total Contractual Commitments		273.3
Southwestern Electric Power Co [Member] \| Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2]	133.7
For 2-3 years	[2]	84.7
For 4-5 years	[2]	0
After 5 years	[2]	0
Total Contractual Commitments	[2]	218.4
Southwestern Electric Power Co [Member] \| Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		10.1
For 2-3 years		31.6
For 4-5 years		13.2
After 5 years		0
Total Contractual Commitments		$ 54.9
AEP Generating Co [Member] \| Rockport Plant, Unit 2 [Member]
Commitments, Guarantees and Contingencies (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
AEP Generating Co [Member] \| Rockport Plant Litigation [Member] \| Rockport Plant, Unit 2 [Member]
Commitments, Guarantees and Contingencies (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
Decommissioning and Low Level Waste Accumulation Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals)
Cost of Decommissioning and Disposal of Radioactive Waste		$ 2,200
Additional Ongoing Costs for Post Decommissioning Storage of SNF		7
Subsequent Decommissioning of the Spent Fuel Storage Facility		33
Amount Recovered in Rates for Decommissioning Costs		2	4	$ 4
Decommissioning Trust Assets Amount		3,000	3,500
Decommissioning and Low Level Waste Accumulation Disposal [Member] \| Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals)
Cost of Decommissioning and Disposal of Radioactive Waste		2,200
Additional Ongoing Costs for Post Decommissioning Storage of SNF		7
Subsequent Decommissioning of the Spent Fuel Storage Facility		33
Amount Recovered in Rates for Decommissioning Costs		2	4	4
Decommissioning Trust Assets Amount		3,000	3,500
Spent Nuclear Fuel Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals)
DOE SNF Disposal Fee		0
Disposal, Assessed Fees and Related Interest		286	281
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		330	329
Recovery of Spent Nuclear Fuel Storage Costs		3	14	24
Current Amount Recoverable from the Federal Government		21	3
Noncurrent Amount Recoverable from the Federal Government		3	21
Spent Nuclear Fuel Disposal [Member] \| Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals)
DOE SNF Disposal Fee		0
Disposal, Assessed Fees and Related Interest		286	281
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		330	329
Recovery of Spent Nuclear Fuel Storage Costs		3	14	$ 24
Current Amount Recoverable from the Federal Government		21	3
Noncurrent Amount Recoverable from the Federal Government		3	$ 21
Nuclear Incident Liability [Member]
Commitments, Guarantees and Contingencies (Textuals)
Insurance Coverage for Property Damage, Decommissioning and Decontamination		2,700
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		500
Contingent Financial Obligation for Mutual Insurance		41
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,700
Commercially Available Insurance		450
Assessed Amount per Nuclear Incident		275
Deferred Premium Assessment Annual Payment		41
Commercially Available Insurance for Catastrophic Nature		450
Liability Coverage Under the Price-Anderson Act		13,200
Nuclear Incident Liability [Member] \| Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals)
Insurance Coverage for Property Damage, Decommissioning and Decontamination		2,700
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		500
Contingent Financial Obligation for Mutual Insurance		41
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,700
Commercially Available Insurance		450
Assessed Amount per Nuclear Incident		275
Deferred Premium Assessment Annual Payment		41
Commercially Available Insurance for Catastrophic Nature		450
Liability Coverage Under the Price-Anderson Act		13,200
March 2026 [Member] \| Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals)
Revolving Credit Facilities		4,000
March 2023 [Member] \| Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals)
Revolving Credit Facilities		$ 1,000

[1]Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.[2]Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

Acquisitions, Assets and Liab_3

Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments (Details)		3 Months Ended				12 Months Ended
		Dec. 31, 2022 USD ($) MW	Sep. 30, 2022 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2020 USD ($)	Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Utilities Operating Expense, Operations						$ 2,878,100,000	$ 2,547,700,000	$ 2,572,400,000
Additional Paid in Capital		$ 8,051,000,000				8,051,000,000	7,172,600,000
Asset Retirement Obligation, Liabilities Settled	[1],[2],[3],[4],[5],[6]					47,000,000	41,400,000
Property, Plant and Equipment, Generation		25,834,200,000				25,834,200,000	24,319,600,000
Obligations Under Operating Leases		$ 552,500,000				552,500,000	501,400,000
Proceeds from Sale of Property, Plant, and Equipment						$ (218,000,000)	(118,900,000)	71,100,000
Equity Method Investment, Ownership Percentage		50%				50%
Deferred Tax Assets		$ 3,567,400,000				$ 3,567,400,000	3,347,100,000
Depreciation and Amortization of Property, Plant and Equipment						3,072,800,000	2,717,100,000	2,487,500,000
Asset Impairments and Other Related Charges						$ 48,800,000	11,600,000	0
BP Wind Energy [Member]
Equity Method Investment, Ownership Percentage		50%				50%
North Central Wind Energy Facilities
Payments to Acquire Property, Plant, and Equipment						$ 1,207,300,000	652,800,000	0
Dry Lake Solar Project [Member]
Payments to Acquire Property, Plant, and Equipment						0	114,400,000	0
Vertically Integrated Utilities [Member]
Enterprise Value		$ 2,850,000,000				2,850,000,000
Pretax Reduction in Investment Basis							363,000,000
Asset Impairments and Other Related Charges						24,900,000	11,600,000
Vertically Integrated Utilities [Member] \| Proceeds for KY Operations
Enterprise Value		2,646,000,000				$ 2,646,000,000
Vertically Integrated Utilities [Member] \| Sundance [Member]
WindGenerationMWs \| MW						199
Vertically Integrated Utilities [Member] \| Maverick [Member]
WindGenerationMWs \| MW						287
Vertically Integrated Utilities [Member] \| Traverse [Member]
WindGenerationMWs \| MW						998
Vertically Integrated Utilities [Member] \| Kentucky Power Company and Kentucky Transmission Company
Deferred Tax Assets		$ 66,100,000				$ 66,100,000
Vertically Integrated Utilities [Member] \| North Central Wind Energy Facilities \| Maverick [Member]
Payments to Acquire Property, Plant, and Equipment						383,000,000
Vertically Integrated Utilities [Member] \| North Central Wind Energy Facilities \| Traverse [Member]
Payments to Acquire Property, Plant, and Equipment						1,200,000,000
Generation and Marketing [Member]
Asset Impairments and Other Related Charges						$ 0	0
Generation and Marketing [Member] \| BP Wind Energy [Member]
Equity Method Investment, Other than Temporary Impairment			$ 2,000,000	$ 186,000,000
Equity Method Investment, Ownership Percentage		50%				50%
Generation and Marketing [Member] \| Proceeds of Mineral Rights Sale
Proceeds from Sale of Property, Plant, and Equipment						$ 120,000,000
Gain (Loss) on Disposition of Other Assets						116,000,000
Generation and Marketing [Member] \| Dry Lake Solar Project [Member]
Payments to Acquire Property, Plant, and Equipment						114,000,000
Generation and Marketing [Member] \| Dry Lake Solar Project [Member] \| Payment When Put in Service
Payments to Acquire Property, Plant, and Equipment						11,000,000
Generation and Marketing [Member] \| Dry Lake Solar Project [Member] \| Payment at Closing
Payments to Acquire Property, Plant, and Equipment						103,000,000
Transmission and Distribution Companies [Member]
Asset Impairments and Other Related Charges						0	0
AEP Transmission Holdco
Enterprise Value		$ 2,850,000,000				2,850,000,000
Asset Impairments and Other Related Charges						0	0
AEP Transmission Holdco \| Proceeds for KY Operations
Enterprise Value		2,646,000,000				2,646,000,000
AEP Texas Inc. [Member]
Utilities Operating Expense, Operations						594,200,000	489,500,000	488,900,000
Additional Paid in Capital		1,558,200,000				1,558,200,000	1,553,900,000
Asset Retirement Obligation, Liabilities Settled	[2],[3]					200,000	400,000
Obligations Under Operating Leases		67,800,000				67,800,000	61,300,000
Deferred Tax Assets		177,000,000				177,000,000	173,800,000
Depreciation and Amortization of Property, Plant and Equipment						363,500,000	327,200,000	364,200,000
AEP Transmission Co [Member]
Utilities Operating Expense, Operations						136,300,000	105,500,000	99,800,000
Payments to Acquire Property, Plant, and Equipment						9,800,000	17,900,000	6,000,000
Obligations Under Operating Leases		1,500,000				1,500,000	1,300,000
Deferred Tax Assets		165,000,000				165,000,000	161,200,000
Depreciation and Amortization of Property, Plant and Equipment						346,200,000	297,300,000	249,000,000
AEP Transmission Co [Member] \| AEP Transmission Holdco
Depreciation and Amortization of Property, Plant and Equipment						4,000,000
Appalachian Power Co [Member]
Utilities Operating Expense, Operations						724,100,000	610,000,000	530,500,000
Additional Paid in Capital		1,828,700,000				1,828,700,000	1,828,700,000
Asset Retirement Obligation, Liabilities Settled	[2],[3]					12,700,000	6,900,000
Property, Plant and Equipment, Generation		6,776,800,000				6,776,800,000	6,683,900,000
Obligations Under Operating Leases		59,100,000				59,100,000	52,400,000
Deferred Tax Assets		510,300,000				510,300,000	495,100,000
Depreciation and Amortization of Property, Plant and Equipment						576,100,000	547,000,000	507,800,000
Asset Impairments and Other Related Charges						24,900,000	0	0
Indiana Michigan Power Co [Member]
Cost of Purchased Power from Affiliate						241,800,000	217,900,000	172,800,000
Utilities Operating Expense, Operations						621,000,000	645,200,000	650,000,000
Additional Paid in Capital		988,800,000				988,800,000	980,900,000
Asset Retirement Obligation, Liabilities Settled	[2],[3],[4]					600,000	100,000
Property, Plant and Equipment, Generation		5,585,100,000				5,585,100,000	5,531,800,000
Obligations Under Operating Leases		48,900,000				48,900,000	48,900,000
Deferred Tax Assets		933,700,000				933,700,000	1,072,200,000
Depreciation and Amortization of Property, Plant and Equipment						511,900,000	424,900,000	393,300,000
Ohio Power Co [Member]
Cost of Purchased Power from Affiliate						9,800,000	51,900,000	119,700,000
Utilities Operating Expense, Operations						982,000,000	836,800,000	822,600,000
Additional Paid in Capital		837,800,000				837,800,000	838,800,000
Asset Retirement Obligation, Liabilities Settled	[2]					100,000	100,000
Obligations Under Operating Leases		60,300,000				60,300,000	68,600,000
Deferred Tax Assets		218,800,000				218,800,000	204,400,000
Depreciation and Amortization of Property, Plant and Equipment						293,100,000	301,100,000	275,000,000
Public Service Co Of Oklahoma [Member]
Utilities Operating Expense, Operations						400,400,000	353,800,000	327,300,000
Additional Paid in Capital		1,042,600,000				1,042,600,000	1,039,000,000
Asset Retirement Obligation, Liabilities Settled	[2],[3],[6]					700,000	700,000
Payments to Acquire Property, Plant, and Equipment						(549,300,000)	(297,000,000)	0
Property, Plant and Equipment, Generation		2,394,800,000				2,394,800,000	1,802,400,000
Obligations Under Operating Leases		99,300,000				99,300,000	62,200,000
Deferred Tax Assets		225,000,000				225,000,000	170,000,000
Depreciation and Amortization of Property, Plant and Equipment						226,200,000	185,900,000	171,900,000
Southwestern Electric Power Co [Member]
Utilities Operating Expense, Operations						424,700,000	360,300,000	338,300,000
Additional Paid in Capital		1,442,200,000				1,442,200,000	1,092,200,000
Asset Retirement Obligation, Liabilities Settled	[1],[2],[3],[6]					25,800,000	20,900,000
Property, Plant and Equipment, Generation		5,476,200,000				5,476,200,000	4,734,500,000
Obligations Under Operating Leases		120,200,000				120,200,000	77,700,000
Deferred Tax Assets		374,900,000				374,900,000	336,400,000
Depreciation and Amortization of Property, Plant and Equipment						319,300,000	292,900,000	271,200,000
Asset Impairments and Other Related Charges						0	11,600,000	0
Southwestern Electric Power Co [Member] \| North Central Wind Energy Facilities
Payments to Acquire Property, Plant, and Equipment						658,000,000	355,800,000	0
Southwestern Electric Power Co [Member] \| Vertically Integrated Utilities [Member] \| Dolet Hills Power Station [Member]
Asset Impairments and Other Related Charges						12,000,000
Kentucky Power Co [Member] \| Vertically Integrated Utilities [Member]
Gain (Loss) on Disposition of Business		100,000,000	194,000,000	$ 69,000,000		363,000,000
Gain (Loss) on Disposition of Business net of Tax		79,000,000	$ 149,000,000			297,000,000
Depreciation and Amortization of Property, Plant and Equipment						99,000,000
Conesville Generating Station (Unit No. 4) [Member] \| Generation and Marketing [Member]
Payments for (Proceeds from) Removal Costs					$ 26,000,000		98,000,000
Asset Retirement Obligation, Liabilities Settled							106,000,000
Payments for Removal Costs							72,000,000
Trent and Desert Sky Wind Farms [Member] \| Generation and Marketing [Member]
Additional Paid in Capital		$ 6,000,000				$ 6,000,000
Mitchell Power Plant
Approximate OVEC Generating Capacity (MWs) \| MW		1,560				1,560
NBV Mitchell Including CWIP and Inventory		$ 577,000,000				$ 577,000,000	586,000,000
Mitchell Power Plant \| Kentucky Power Co [Member]
Ownership Interest in Mitchell Power Plant		50%				50%
Mitchell Power Plant \| Wheeling Power Company
Ownership Interest in Mitchell Power Plant		50%				50%
Cardinal Power Plant \| Generation and Marketing [Member]
Approximate OVEC Generating Capacity (MWs) \| MW		595				595
AEP Wind Holdings LLC [Member] \| Generation and Marketing [Member]
Guarantor Obligations, Current Carrying Value		$ 5,000,000				$ 5,000,000
AEP Wind Holdings LLC [Member] \| Indiana Michigan Power Co [Member] \| Generation and Marketing [Member]
Cost of Purchased Power from Affiliate						12,000,000	10,000,000	11,000,000
AEP Wind Holdings LLC [Member] \| Ohio Power Co [Member] \| Generation and Marketing [Member]
Cost of Purchased Power from Affiliate						24,000,000	20,000,000	23,000,000
AEP Wind Holdings LLC [Member] \| Southwestern Electric Power Co [Member] \| Generation and Marketing [Member]
Cost of Purchased Power from Affiliate						$ 14,000,000	14,000,000	14,000,000
Santa Rita East [Member]
Noncash or Part Noncash Acquisition, Other Assets Acquired							18,900,000	(43,700,000)
Santa Rita East [Member] \| Noncontrolling Interests [Member]
Noncash or Part Noncash Acquisition, Other Assets Acquired							18,900,000	$ (43,700,000)
Santa Rita East [Member] \| Generation and Marketing [Member]
Noncash Contribution of Assets by Noncontrolling Interest							44,000,000
Percentage of an Asset Acquired		85%				85%		10%
WindGenerationMWs \| MW						302
Payments to Acquire Businesses, Gross							44,000,000
Dry Lake Solar Project [Member]
Percentage of an Asset Acquired		75%				75%
Dry Lake Solar Project [Member] \| Generation and Marketing [Member]
Solar Generation MWs \| MW						100
North Central Wind Energy Facilities
Payments to Acquire Property, Plant, and Equipment						$ 2,000,000,000
North Central Wind Energy Facilities \| Vertically Integrated Utilities [Member]
WindGenerationMWs \| MW						1,484
North Central Wind Energy Facilities \| Vertically Integrated Utilities [Member] \| Sundance [Member]
Payments to Acquire Property, Plant, and Equipment						$ 270,000,000
North Central Wind Energy Facilities \| Public Service Co Of Oklahoma [Member]
Percentage of an Asset Acquired		45.50%				45.50%
North Central Wind Energy Facilities \| Public Service Co Of Oklahoma [Member] \| Vertically Integrated Utilities [Member]
Property, Plant and Equipment, Generation		$ 901,000,000				$ 901,000,000	316,000,000
Obligations Under Operating Leases		70,400,000				70,400,000	30,600,000
North Central Wind Energy Facilities \| Public Service Co Of Oklahoma [Member] \| Vertically Integrated Utilities [Member] \| Sundance [Member]
Obligations Under Operating Leases		12,600,000				12,600,000	12,600,000
North Central Wind Energy Facilities \| Public Service Co Of Oklahoma [Member] \| Vertically Integrated Utilities [Member] \| Maverick [Member]
Obligations Under Operating Leases		18,000,000				18,000,000	18,000,000
North Central Wind Energy Facilities \| Public Service Co Of Oklahoma [Member] \| Vertically Integrated Utilities [Member] \| Traverse [Member]
Obligations Under Operating Leases		$ 39,800,000				$ 39,800,000	0
North Central Wind Energy Facilities \| Southwestern Electric Power Co [Member]
Percentage of an Asset Acquired		54.50%				54.50%
North Central Wind Energy Facilities \| Southwestern Electric Power Co [Member] \| Vertically Integrated Utilities [Member]
Property, Plant and Equipment, Generation		$ 1,100,000,000				$ 1,100,000,000	378,000,000
Obligations Under Operating Leases		84,400,000				84,400,000	36,700,000
North Central Wind Energy Facilities \| Southwestern Electric Power Co [Member] \| Vertically Integrated Utilities [Member] \| Sundance [Member]
Obligations Under Operating Leases		15,100,000				15,100,000	15,100,000
North Central Wind Energy Facilities \| Southwestern Electric Power Co [Member] \| Vertically Integrated Utilities [Member] \| Maverick [Member]
Obligations Under Operating Leases		21,600,000				21,600,000	21,600,000
North Central Wind Energy Facilities \| Southwestern Electric Power Co [Member] \| Vertically Integrated Utilities [Member] \| Traverse [Member]
Obligations Under Operating Leases		47,700,000				47,700,000	0
Trent and Desert Sky Wind Farms [Member] \| Generation and Marketing [Member]
Payments to Acquire Businesses, Gross						57,000,000
Redeemable Noncontrolling Interest		$ 63,000,000				63,000,000
Noncontrolling Interests [Member] \| Dry Lake Solar Project [Member]
Noncash Contribution of Assets by Noncontrolling Interest						$ 0	$ 35,300,000	$ 0

[1]Includes ARO related to Sabine and DHLC.[2]Includes ARO related to asbestos removal.[3]Includes ARO related to ash disposal facilities.[4]Includes ARO related to nuclear decommissioning costs for the Cook Plant of $2 billion and $1.93 billion as of December 31, 2022 and 2021, respectively.[5]Includes ARO related to solar farms.[6]Includes ARO related to wind farms.

Benefit Plans 1 (Details)

Benefit Plans 1 (Details) - USD ($) $ in Millions		12 Months Ended
Benefit Plans 1 (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		$ 3,757.4	$ 4,433.1
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(607.3)	(603.8)
AEP Texas Inc. [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		179	211.3
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(93.2)	(73.8)
Appalachian Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		138.7	129.2
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(49.6)	(34.6)
Indiana Michigan Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		270.5	316.5
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(58.8)	(58.3)
Ohio Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		578.3	601.1
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(66)	(29.2)
Public Service Co Of Oklahoma [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		20.8	7.9
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(21.3)	(19.4)
Southwestern Electric Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		262	251.8
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		$ (68.4)	$ (63)
Pension Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	5.05%	5.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	5.05%	5.10%	5%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 5,187	$ 5,544.5
Service Cost		123.1	129.2	$ 111.9
Interest Cost		148.2	137.2	167.9
Actuarial (Gain) Loss		(983.4)	(173.9)
Plan Amendments		0	0
Benefit Payments		(402.2)	(450)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		4,072.7	5,187	5,544.5
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		5,352.9	5,556.6
Actual Gain (Loss) on Plan Assets		(833.7)	239.2
Company Contributions	[3]	7.7	7.1
Participant Contributions		0	0
Benefit Payments		(402.2)	(450)
Fair Value of Plan Assets as of December 31		4,124.7	5,352.9	$ 5,556.6
Funded (Underfunded) Status as of December 31		52	165.9
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		113.4	244.3
Other Current Liabilities - Accrued Short-term Benefit Liability		(6.3)	(7.6)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(55.1)	(70.8)
Funded (Underfunded) Status		52	165.9
Components
Net Actuarial Loss		935.6	894.7
Prior Service Cost (Credit)		0.2	0.2
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		103.9	(183.4)
Amortization of Actuarial Gain (Loss)		(63)	(101.5)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 40.9	$ (284.9)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5.05%	5.10%
Company Contributions	[3]	$ 7.7	$ 7.1
Pension Plans [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		841.8	878
Pension Plans [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		19.9	3.6
Pension Plans [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 74.1	$ 13.3
Pension Plans [Member] \| AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	5.15%	5.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	5.15%	5.10%	5.05%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 419.8	$ 453.2
Service Cost		11.1	11.8	$ 10
Interest Cost		12.1	11.2	13.9
Actuarial (Gain) Loss		(67.8)	(10.9)
Plan Amendments		0	0
Benefit Payments		(41.1)	(45.5)
Participant Contributions		0	0
Benefit Obligation as of December 31		334.1	419.8	453.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		444.9	474
Actual Gain (Loss) on Plan Assets		(69.2)	16
Company Contributions		0.5	0.4
Participant Contributions		0	0
Benefit Payments		(41.1)	(45.5)
Fair Value of Plan Assets as of December 31		335.1	444.9	$ 474
Funded (Underfunded) Status as of December 31		1	25.1
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		3.7	28.7
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.4)	(0.3)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(2.3)	(3.3)
Funded (Underfunded) Status		1	25.1
Components
Net Actuarial Loss		161.9	144.7
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		22.4	(7.5)
Amortization of Actuarial Gain (Loss)		(5.2)	(8.3)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 17.2	$ (15.8)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5.15%	5.10%
Company Contributions		$ 0.5	$ 0.4
Pension Plans [Member] \| AEP Texas Inc. [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		151.2	136.7
Pension Plans [Member] \| AEP Texas Inc. [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		2.4	1.8
Pension Plans [Member] \| AEP Texas Inc. [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 8.3	$ 6.2
Pension Plans [Member] \| Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	4.90%	4.85%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	4.90%	4.85%	4.85%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 621.7	$ 670.8
Service Cost		11.4	11.9	$ 10.5
Interest Cost		17.5	16.4	20.3
Actuarial (Gain) Loss		(123.1)	(28.5)
Plan Amendments		0	0
Benefit Payments		(41.8)	(48.9)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		485.7	621.7	670.8
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		683.3	701.3
Actual Gain (Loss) on Plan Assets		(109.8)	30.9
Company Contributions		0	0
Participant Contributions		0	0
Benefit Payments		(41.8)	(48.9)
Fair Value of Plan Assets as of December 31		531.7	683.3	$ 701.3
Funded (Underfunded) Status as of December 31		46	61.6
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		46.6	62.4
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(0.6)	(0.8)
Funded (Underfunded) Status		46	61.6
Components
Net Actuarial Loss		95.6	83.9
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		19.1	(30.4)
Amortization of Actuarial Gain (Loss)		(7.4)	(12)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 11.7	$ (42.4)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.90%	4.85%
Company Contributions		$ 0	$ 0
Pension Plans [Member] \| Appalachian Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		93.6	82.5
Pension Plans [Member] \| Appalachian Power Co [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		0.4	0.3
Pension Plans [Member] \| Appalachian Power Co [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 1.6	$ 1.1
Pension Plans [Member] \| Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	5%	5%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	5%	5%	5%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 612.1	$ 653.3
Service Cost		16.2	17.5	$ 15.4
Interest Cost		17	16.2	19.7
Actuarial (Gain) Loss		(138)	(29.5)
Plan Amendments		0	0
Benefit Payments		(40.5)	(45.4)
Participant Contributions		0	0
Benefit Obligation as of December 31		466.8	612.1	653.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		681.5	698.1
Actual Gain (Loss) on Plan Assets		(107.4)	28.8
Company Contributions		0.1	0
Participant Contributions		0	0
Benefit Payments		(40.5)	(45.4)
Fair Value of Plan Assets as of December 31		533.7	681.5	$ 698.1
Funded (Underfunded) Status as of December 31		66.9	69.4
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		68.5	71.4
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.1)	(0.1)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(1.5)	(1.9)
Funded (Underfunded) Status		66.9	69.4
Components
Net Actuarial Loss		(6.9)	(1.6)
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		1.8	(29.4)
Amortization of Actuarial Gain (Loss)		(7.1)	(11.7)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ (5.3)	$ (41.1)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5%	5%
Company Contributions		$ 0.1	$ 0
Pension Plans [Member] \| Indiana Michigan Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[4]	4.8	3.1
Pension Plans [Member] \| Indiana Michigan Power Co [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		(2.4)	(1)
Pension Plans [Member] \| Indiana Michigan Power Co [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ (9.3)	$ (3.7)
Pension Plans [Member] \| Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	5.35%	5.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	5.35%	5.30%	5.25%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 470.7	$ 510.3
Service Cost		11.2	11.4	$ 9.7
Interest Cost		13.3	12.5	15.4
Actuarial (Gain) Loss		(97.9)	(24.1)
Plan Amendments		0	0
Benefit Payments		(33.7)	(39.4)
Participant Contributions		0	0
Benefit Obligation as of December 31		363.6	470.7	510.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		524.8	543.1
Actual Gain (Loss) on Plan Assets		(84.8)	21.1
Company Contributions		0.1	0
Participant Contributions		0	0
Benefit Payments		(33.7)	(39.4)
Fair Value of Plan Assets as of December 31		406.4	524.8	$ 543.1
Funded (Underfunded) Status as of December 31		42.8	54.1
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		43.1	54.8
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(0.3)	(0.7)
Funded (Underfunded) Status		42.8	54.1
Components
Net Actuarial Loss		124.3	118.1
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		11.7	(22.8)
Amortization of Actuarial Gain (Loss)		(5.5)	(9.1)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 6.2	$ (31.9)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5.35%	5.30%
Company Contributions		$ 0.1	$ 0
Pension Plans [Member] \| Ohio Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 124.3	$ 118.1
Pension Plans [Member] \| Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	5.15%	5.10%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	5.15%	5.10%	5.05%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 252.6	$ 279.9
Service Cost		7.4	8	$ 7.3
Interest Cost		7	6.7	8.5
Actuarial (Gain) Loss		(52.9)	(17.2)
Plan Amendments		0	0
Benefit Payments		(21.8)	(24.8)
Participant Contributions		0	0
Benefit Obligation as of December 31		192.3	252.6	279.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		286.2	299.8
Actual Gain (Loss) on Plan Assets		(46)	11.1
Company Contributions		0.1	0.1
Participant Contributions		0	0
Benefit Payments		(21.8)	(24.8)
Fair Value of Plan Assets as of December 31		218.5	286.2	$ 299.8
Funded (Underfunded) Status as of December 31		26.2	33.6
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		27.6	35.5
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.1)	(0.1)
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(1.3)	(1.8)
Funded (Underfunded) Status		26.2	33.6
Components
Net Actuarial Loss		38.8	35
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		6.7	(16)
Amortization of Actuarial Gain (Loss)		(2.9)	(4.9)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 3.8	$ (20.9)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5.15%	5.10%
Company Contributions		$ 0.1	$ 0.1
Pension Plans [Member] \| Public Service Co Of Oklahoma [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 38.8	$ 35
Pension Plans [Member] \| Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Interest Crediting Rate		4.25%	4%
Rate of Compensation Increase	[1]	5%	4.95%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.50%	3.25%
Interest Crediting Rate		4%	4%	4%
Expected Return on Plan Assets		5.25%	4.75%	5.75%
Rate of Compensation Increase	[2]	5%	4.95%	4.90%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 317.7	$ 334.5
Service Cost		10.6	11.2	$ 9.9
Interest Cost		9.1	8.5	10.2
Actuarial (Gain) Loss		(57.9)	(3.5)
Plan Amendments		0	0
Benefit Payments		(28.8)	(33)
Participant Contributions		0	0
Benefit Obligation as of December 31		250.7	317.7	334.5
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		308.3	326.9
Actual Gain (Loss) on Plan Assets		(48.3)	14.3
Company Contributions		0.1	0.1
Participant Contributions		0	0
Benefit Payments		(28.8)	(33)
Fair Value of Plan Assets as of December 31		231.3	308.3	$ 326.9
Funded (Underfunded) Status as of December 31		(19.4)	(9.4)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.1)	(0.1)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(19.3)	(9.3)
Funded (Underfunded) Status		(19.4)	(9.4)
Components
Net Actuarial Loss		77.6	76.4
Prior Service Cost (Credit)		0	0
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		5	(4.3)
Amortization of Actuarial Gain (Loss)		(3.8)	(6.2)
Prior Service (Credit) Cost		0	0
Amortization of Prior Service Credit (Cost)		0	0
Change for the Year		$ 1.2	$ (10.5)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	5%	4.95%
Company Contributions		$ 0.1	$ 0.1
Pension Plans [Member] \| Southwestern Electric Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		77.6	76.4
Pension Plans [Member] \| Southwestern Electric Power Co [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		0	0
Pension Plans [Member] \| Southwestern Electric Power Co [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 0	0
Pension Plans [Member] \| Minimum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Minimum [Member] \| AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Minimum [Member] \| Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Minimum [Member] \| Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Minimum [Member] \| Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Minimum [Member] \| Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Minimum [Member] \| Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3%
Pension Plans [Member] \| Maximum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Pension Plans [Member] \| Maximum [Member] \| AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Pension Plans [Member] \| Maximum [Member] \| Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Pension Plans [Member] \| Maximum [Member] \| Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Pension Plans [Member] \| Maximum [Member] \| Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Pension Plans [Member] \| Maximum [Member] \| Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Pension Plans [Member] \| Maximum [Member] \| Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		11.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		11.50%
Nonqualified Pension Plans [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 78.4
Benefit Obligation as of December 31		61.5	78.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Company Contributions		8	7
Fair Value of Plan Assets as of December 31		0	0
Benefit Plans (Textuals) [Abstract]
Company Contributions		8	7
Nonqualified Pension Plans [Member] \| AEP Texas Inc. [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		3.6
Benefit Obligation as of December 31		2.7	3.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] \| Appalachian Power Co [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		0.8
Benefit Obligation as of December 31		0.6	0.8
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] \| Indiana Michigan Power Co [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		1.9
Benefit Obligation as of December 31		1.6	1.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] \| Ohio Power Co [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		0.7
Benefit Obligation as of December 31		0.3	0.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] \| Public Service Co Of Oklahoma [Member]
Change in Benefit Obligation
Benefit Obligation as of January 1		1.9
Benefit Obligation as of December 31		1.5	1.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		0	0
Nonqualified Pension Plans [Member] \| Southwestern Electric Power Co [Member]
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		0
Fair Value of Plan Assets as of December 31		$ 231.3	$ 0
Other Postretirement Benefit Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 1,041.3	$ 1,210.9
Service Cost		7.4	9.5	$ 10
Interest Cost		29.2	30.5	39.8
Actuarial (Gain) Loss		(109.8)	(120.1)
Plan Amendments		0	(5.4)
Benefit Payments		(140.1)	(126)
Participant Contributions		44.1	41.3
Medicare Subsidy		0.5	0.6
Benefit Obligation as of December 31		872.6	1,041.3	1,210.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		2,044.3	1,946.7
Actual Gain (Loss) on Plan Assets		(403.6)	176.5
Company Contributions	[3]	4.6	5.8
Participant Contributions		44.1	41.3
Benefit Payments		(140.1)	(126)
Fair Value of Plan Assets as of December 31		1,549.3	2,044.3	$ 1,946.7
Funded (Underfunded) Status as of December 31		676.7	1,003
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		699.5	1,040.8
Other Current Liabilities - Accrued Short-term Benefit Liability		(2.5)	(2.7)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(20.3)	(35.1)
Funded (Underfunded) Status		676.7	1,003
Components
Net Actuarial Loss		300	(103.6)
Prior Service Cost (Credit)		(90.5)	(161.9)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		403.6	(205.5)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(5.5)
Amortization of Prior Service Credit (Cost)		71.4	70.9
Change for the Year		475	(140.1)
Benefit Plans (Textuals) [Abstract]
Company Contributions	[3]	4.6	5.8
Other Postretirement Benefit Plans [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		126	(195.1)
Other Postretirement Benefit Plans [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		17.5	(14.7)
Other Postretirement Benefit Plans [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 66	$ (55.7)
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 80.5	$ 96.3
Service Cost		0.5	0.7	$ 0.8
Interest Cost		2.2	2.4	3.2
Actuarial (Gain) Loss		(7.1)	(12.3)
Plan Amendments		0	(0.5)
Benefit Payments		(10.9)	(9.3)
Participant Contributions		3.4	3.2
Benefit Obligation as of December 31		68.6	80.5	96.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		168.8	162.3
Actual Gain (Loss) on Plan Assets		(33)	12.5
Company Contributions		0	0.1
Participant Contributions		3.4	3.2
Benefit Payments		(10.9)	(9.3)
Fair Value of Plan Assets as of December 31		128.3	168.8	$ 162.3
Funded (Underfunded) Status as of December 31		59.7	88.3
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		59.7	88.3
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		59.7	88.3
Components
Net Actuarial Loss		29.7	(5.2)
Prior Service Cost (Credit)		(7.6)	(13.7)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		34.9	(17.5)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(0.4)
Amortization of Prior Service Credit (Cost)		6.1	6
Change for the Year		41	(11.9)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0.1
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		22	(17.7)
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		0.1	(0.2)
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 0	$ (1)
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 167.3	$ 198.2
Service Cost		0.8	1	$ 1
Interest Cost		4.7	4.9	6.6
Actuarial (Gain) Loss		(16.2)	(21.4)
Plan Amendments		0	(0.9)
Benefit Payments		(23)	(21.3)
Participant Contributions		7	6.6
Medicare Subsidy		0.1	0.2
Benefit Obligation as of December 31		140.7	167.3	198.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		302.3	293
Actual Gain (Loss) on Plan Assets		(59.3)	21.9
Company Contributions		1.6	2.1
Participant Contributions		7	6.6
Benefit Payments		(23)	(21.3)
Fair Value of Plan Assets as of December 31		228.6	302.3	$ 293
Funded (Underfunded) Status as of December 31		87.9	135
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		106.3	158.1
Other Current Liabilities - Accrued Short-term Benefit Liability		(1.6)	(1.8)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(16.8)	(21.3)
Funded (Underfunded) Status		87.9	135
Components
Net Actuarial Loss		40.5	(18.9)
Prior Service Cost (Credit)		(13.4)	(23.8)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		59.4	(30)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(0.9)
Amortization of Prior Service Credit (Cost)		10.4	10.3
Change for the Year		69.8	(20.6)
Benefit Plans (Textuals) [Abstract]
Company Contributions		1.6	2.1
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		14.7	(19.8)
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		2.5	(4.9)
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 9.9	$ (18)
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 118.6	$ 141.4
Service Cost		0.9	1.3	$ 1.4
Interest Cost		3.4	3.5	4.7
Actuarial (Gain) Loss		(8.7)	(16.8)
Plan Amendments		0	(0.7)
Benefit Payments		(18.3)	(15.3)
Participant Contributions		6	5.2
Benefit Obligation as of December 31		101.9	118.6	141.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		248.7	238.2
Actual Gain (Loss) on Plan Assets		(45.9)	20.6
Company Contributions		0	0
Participant Contributions		6	5.2
Benefit Payments		(18.3)	(15.3)
Fair Value of Plan Assets as of December 31		190.5	248.7	$ 238.2
Funded (Underfunded) Status as of December 31		88.6	130.1
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		88.6	130.1
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		88.6	130.1
Components
Net Actuarial Loss		40.2	(10.7)
Prior Service Cost (Credit)		(12.4)	(22.1)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		50.9	(26.3)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(0.7)
Amortization of Prior Service Credit (Cost)		9.7	9.6
Change for the Year		60.6	(17.4)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets	[4]	22.1	(30.7)
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		1.2	(0.4)
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 4.5	$ (1.7)
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 104.9	$ 126.4
Service Cost		0.6	0.8	$ 0.9
Interest Cost		3	3	4.2
Actuarial (Gain) Loss		(8.9)	(15.6)
Plan Amendments		0	(0.6)
Benefit Payments		(15.5)	(13.6)
Participant Contributions		4.8	4.5
Benefit Obligation as of December 31		88.9	104.9	126.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		220	213
Actual Gain (Loss) on Plan Assets		(43.1)	16.1
Company Contributions		0	0
Participant Contributions		4.8	4.5
Benefit Payments		(15.5)	(13.6)
Fair Value of Plan Assets as of December 31		166.2	220	$ 213
Funded (Underfunded) Status as of December 31		77.3	115.1
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		77.3	115.1
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		77.3	115.1
Components
Net Actuarial Loss		27.6	(18.5)
Prior Service Cost (Credit)		(9.2)	(16.3)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		46.1	(22.1)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(0.6)
Amortization of Prior Service Credit (Cost)		7.1	7.2
Change for the Year		53.2	(15.5)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 18.4	$ (34.8)
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 54.4	$ 64
Service Cost		0.4	0.6	$ 0.7
Interest Cost		1.5	1.6	2.1
Actuarial (Gain) Loss		(5.2)	(6.8)
Plan Amendments		0	(0.3)
Benefit Payments		(7.9)	(7)
Participant Contributions		2.5	2.3
Benefit Obligation as of December 31		45.7	54.4	64
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		114	107.8
Actual Gain (Loss) on Plan Assets		(23.2)	10.9
Company Contributions		0	0
Participant Contributions		2.5	2.3
Benefit Payments		(7.9)	(7)
Fair Value of Plan Assets as of December 31		85.4	114	$ 107.8
Funded (Underfunded) Status as of December 31		39.7	59.6
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		39.7	59.6
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		39.7	59.6
Components
Net Actuarial Loss		22	(2.1)
Prior Service Cost (Credit)		(5.6)	(10)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		24.1	(12.6)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(0.3)
Amortization of Prior Service Credit (Cost)		4.4	4.4
Change for the Year		28.5	(8.5)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 16.4	$ (12.1)
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		5.50%	2.90%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		2.90%	2.55%	3.30%
Expected Return on Plan Assets		5.50%	4.75%	5.50%
Health Care Trend Rates
Initial		7.50%	6.25%
Ultimate		4.50%	4.50%
Year Ultimate Reached		2029	2029
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 65.2	$ 77.1
Service Cost		0.6	0.8	$ 0.8
Interest Cost		1.8	1.9	2.5
Actuarial (Gain) Loss		(6.6)	(9.2)
Plan Amendments		0	(0.4)
Benefit Payments		(8.8)	(7.6)
Participant Contributions		2.9	2.6
Benefit Obligation as of December 31		55.1	65.2	77.1
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		136.6	129.9
Actual Gain (Loss) on Plan Assets		(27.7)	11.7
Company Contributions		0	0
Participant Contributions		2.9	2.6
Benefit Payments		(8.8)	(7.6)
Fair Value of Plan Assets as of December 31		103	136.6	$ 129.9
Funded (Underfunded) Status as of December 31		47.9	71.4
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		47.9	71.4
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		47.9	71.4
Components
Net Actuarial Loss		25	(3.5)
Prior Service Cost (Credit)		(7)	(12.3)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		28.5	(15)
Amortization of Actuarial Gain (Loss)		0	0
Prior Service (Credit) Cost		0	(0.4)
Amortization of Prior Service Credit (Cost)		5.3	5.3
Change for the Year		33.8	(10.1)
Benefit Plans (Textuals) [Abstract]
Company Contributions		0	0
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member] \| Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		11.2	(8.9)
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member] \| Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		1.5	(1.4)
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member] \| Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI, Income Tax Expense and Regulatory Assets		$ 5.3	$ (5.5)

[1]Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.[2]Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.[3]No contributions were made to the qualified pension plan for the years ended December 31, 2022 and 2021, respectively. Contributions to the non-qualified pension plans were $8 million and $7 million for the years ended December 31, 2022 and 2021, respectively.[4]Recorded as a Regulatory Asset as of December 31, 2022 and recorded as a Regulatory Liability as of December 31, 2021.

Benefit Plans 2 (Details)

Benefit Plans 2 (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4,124.7	$ 5,352.9	$ 5,556.6
Year End Allocation
Total		100%	100%
Pension Plan [Member] \| AEP Texas Inc. [Member]
Allocated Assets of Investments		8.10%	8.30%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 335.1	$ 444.9	474
Pension Plan [Member] \| Appalachian Power Co [Member]
Allocated Assets of Investments		12.90%	12.80%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 531.7	$ 683.3	701.3
Pension Plan [Member] \| Indiana Michigan Power Co [Member]
Allocated Assets of Investments		12.90%	12.70%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 533.7	$ 681.5	698.1
Pension Plan [Member] \| Ohio Power Co [Member]
Allocated Assets of Investments		9.90%	9.80%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 406.4	$ 524.8	543.1
Pension Plan [Member] \| Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments		5.30%	5.30%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 218.5	$ 286.2	299.8
Pension Plan [Member] \| Southwestern Electric Power Co [Member]
Allocated Assets of Investments		5.60%	5.80%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 231.3	$ 308.3	326.9
Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 1,549.3	$ 2,044.3	1,946.7
Year End Allocation
Total		100%	100%
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member]
Allocated Assets of Investments		8.30%	8.30%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 128.3	$ 168.8	162.3
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member]
Allocated Assets of Investments		14.80%	14.80%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 228.6	$ 302.3	293
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member]
Allocated Assets of Investments		12.30%	12.20%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 190.5	$ 248.7	238.2
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member]
Allocated Assets of Investments		10.70%	10.80%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 166.2	$ 220	213
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments		5.50%	5.60%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 85.4	$ 114	107.8
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member]
Allocated Assets of Investments		6.60%	6.70%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 103	$ 136.6	$ 129.9
Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,173.3	1,262.6
Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		300.9	445.4
Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		745.4	854.7
Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		765.3	895.2
Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,206	3,235.6
Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		483.1	703.7
Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Equity Securities [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 1,125.9	$ 1,318.5
Year End Allocation
Total	[1]	27.30%	24.60%
Equity Securities [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 848.2	$ 1,035.3
Year End Allocation
Total		54.70%	50.70%
Equity Securities [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 379.9	$ 463.9
Equity Securities [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		169.1	265
Equity Securities [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	746	854.6
Equity Securities [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		679.1	770.3
Equity Securities [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Equity Securities [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Equity Securities [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Equity Securities [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Domestic [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 347.6	$ 388.9
Year End Allocation
Total	[1]	8.40%	7.20%
Domestic [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 414.1	$ 474
Year End Allocation
Total		26.70%	23.20%
Domestic [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
Domestic [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Domestic [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	347.6	388.9
Domestic [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		414.1	474
Domestic [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Domestic [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Domestic [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Domestic [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
International [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 398.4	$ 465.7
Year End Allocation
Total	[1]	9.70%	8.70%
International [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 265	$ 296.3
Year End Allocation
Total		17.10%	14.50%
International [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
International [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
International [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	398.4	465.7
International [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		265	296.3
International [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
International [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
International [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
International [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Common Collective Trusts [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1],[2]	$ 379.9	$ 463.9
Year End Allocation
Total	[1],[2]	9.20%	8.70%
Common Collective Trusts [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	$ 169.1	$ 265
Year End Allocation
Total	[3]	10.90%	13%
Common Collective Trusts [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1],[2]	$ 379.9	$ 463.9
Common Collective Trusts [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	169.1	265
Common Collective Trusts [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1],[2]	0	0
Common Collective Trusts [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Common Collective Trusts [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1],[2]	0	0
Common Collective Trusts [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Common Collective Trusts [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1],[2]	0	0
Common Collective Trusts [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Fixed Income [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 2,140.5	$ 3,171.4
Year End Allocation
Total	[1]	51.90%	59.20%
Fixed Income [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 509.4	$ 768.6
Year End Allocation
Total		33%	37.60%
Fixed Income [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
Fixed Income [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		120.3	167.7
Fixed Income [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	(0.6)	0.1
Fixed Income [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		63	91.9
Fixed Income [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	2,141.1	3,171.3
Fixed Income [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		326.1	509
Fixed Income [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Fixed Income [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Common Collective Trust - Debt [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	$ 120.3	$ 167.7
Year End Allocation
Total	[3]	7.80%	8.20%
Common Collective Trust - Debt [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	$ 120.3	$ 167.7
Common Collective Trust - Debt [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Common Collective Trust - Debt [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Common Collective Trust - Debt [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
United States Government and Agency Securities [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 1,070.8	$ 1,557.7
Year End Allocation
Total	[1]	26%	29.10%
United States Government and Agency Securities [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 155.9	$ 222.4
Year End Allocation
Total		10.10%	10.90%
United States Government and Agency Securities [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
United States Government and Agency Securities [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
United States Government and Agency Securities [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	(0.6)	0.1
United States Government and Agency Securities [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0.1	0
United States Government and Agency Securities [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	1,071.4	1,557.6
United States Government and Agency Securities [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		155.8	222.4
United States Government and Agency Securities [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
United States Government and Agency Securities [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Corporate Debt [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 891.7	$ 1,295.9
Year End Allocation
Total	[1]	21.60%	24.20%
Corporate Debt [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 141.5	$ 233.2
Year End Allocation
Total		9.10%	11.40%
Corporate Debt [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
Corporate Debt [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Corporate Debt [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Corporate Debt [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Corporate Debt [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	891.7	1,295.9
Corporate Debt [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		141.5	233.2
Corporate Debt [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Corporate Debt [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Foreign Debt [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 140.2	$ 259.4
Year End Allocation
Total	[1]	3.40%	4.80%
Foreign Debt [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 21	$ 39.8
Year End Allocation
Total		1.40%	2%
Foreign Debt [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
Foreign Debt [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Foreign Debt [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Foreign Debt [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Foreign Debt [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	140.2	259.4
Foreign Debt [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		21	39.8
Foreign Debt [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Foreign Debt [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
State and Local Government [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 37	$ 57.1
Year End Allocation
Total	[1]	0.90%	1.10%
State and Local Government [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 70.7	$ 105.5
Year End Allocation
Total		4.60%	5.10%
State and Local Government [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
State and Local Government [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
State and Local Government [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
State and Local Government [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		62.9	91.9
State and Local Government [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	37	57.1
State and Local Government [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		7.8	13.6
State and Local Government [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
State and Local Government [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Other - Asset Backed [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0.8	$ 1.3
Year End Allocation
Total	[1]	0%	0%
Other - Asset Backed [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	$ 0	$ 0
Other - Asset Backed [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Other - Asset Backed [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0.8	1.3
Other - Asset Backed [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[1]	0	0
Infrastructure [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 109.2	$ 92.1
Year End Allocation
Total	[2]	2.60%	1.70%
Infrastructure [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 109.2	$ 92.1
Infrastructure [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Infrastructure [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Infrastructure [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Real Estate [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 276.9	$ 232.6
Year End Allocation
Total	[2]	6.70%	4.40%
Real Estate [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 276.9	$ 232.6
Real Estate [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Real Estate [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Real Estate [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Alternative Investments [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 319.7	$ 448.8
Year End Allocation
Total	[2]	7.80%	8.40%
Alternative Investments [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 319.7	$ 448.8
Alternative Investments [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Alternative Investments [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Alternative Investments [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Trusted Owned Life Insurance [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 157	$ 194.7
Year End Allocation
Total		10.10%	9.50%
Trusted Owned Life Insurance [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 0	$ 0
Trusted Owned Life Insurance [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Trusted Owned Life Insurance [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		157	194.7
Trusted Owned Life Insurance [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
International Equities [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 46.7	$ 23.4
Year End Allocation
Total		3%	1.10%
International Equities [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 0	$ 0
International Equities [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
International Equities [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		46.7	23.4
International Equities [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
United States Bonds [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 110.3	$ 171.3
Year End Allocation
Total		7.10%	8.40%
United States Bonds [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 0	$ 0
United States Bonds [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
United States Bonds [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		110.3	171.3
United States Bonds [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	0
Cash and Cash Equivalents [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 123.2	$ 117.7
Year End Allocation
Total	[2]	3%	2.20%
Cash and Cash Equivalents [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	$ 29.9	$ 39.7
Year End Allocation
Total	[3]	1.90%	1.90%
Cash and Cash Equivalents [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	$ 58.3	$ 53.4
Cash and Cash Equivalents [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	6.7	6.7
Cash and Cash Equivalents [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Cash and Cash Equivalents [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	23.2	33
Cash and Cash Equivalents [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	64.9	64.3
Cash and Cash Equivalents [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Cash and Cash Equivalents [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[2]	0	0
Cash and Cash Equivalents [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[3]	0	0
Other - Pending Transactions and Accrued Income [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 29.3	$ (28.2)
Year End Allocation
Total	[4]	0.70%	(0.50%)
Other - Pending Transactions and Accrued Income [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ 4.8	$ 6
Year End Allocation
Total	[5]	0.30%	0.30%
Other - Pending Transactions and Accrued Income [Member] \| Other [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 29.3	$ (28.2)
Other - Pending Transactions and Accrued Income [Member] \| Other [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	4.8	6
Other - Pending Transactions and Accrued Income [Member] \| Level 1 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0
Other - Pending Transactions and Accrued Income [Member] \| Level 1 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0	0
Other - Pending Transactions and Accrued Income [Member] \| Level 2 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0
Other - Pending Transactions and Accrued Income [Member] \| Level 2 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0	0
Other - Pending Transactions and Accrued Income [Member] \| Level 3 [Member] \| Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0	0
Other - Pending Transactions and Accrued Income [Member] \| Level 3 [Member] \| Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ 0	$ 0

[1]Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.[2]Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.[3]Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.[4]Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.[5]Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Benefit Plans 3 (Details)

Benefit Plans 3 (Details) - USD ($) $ in Millions	12 Months Ended
Benefit Plans 3 (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 81.9	$ 79.9	$ 81.8
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Multiemployer Plans Withdrawal Obligation	$ 12	22
Noncurrent Regulatory Assets	4,762	4,618.8
Noncurrent Regulatory Liabilities	8,115.6	8,834.4
UMWA Withdrawal Obligation [Member]
Benefit Plans Textuals [Abstract]
Noncurrent Regulatory Assets	0	1
AEP Texas Inc. [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 6.5	6.4	6.4
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Noncurrent Regulatory Assets	$ 298.3	275.2
Noncurrent Regulatory Liabilities	1,259.6	1,242
Appalachian Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 7.8	7.6	7.7
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Noncurrent Regulatory Assets	$ 1,058.6	757.6
Noncurrent Regulatory Liabilities	1,143.6	1,238.8
Indiana Michigan Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 11.1	10.9	11.3
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Noncurrent Regulatory Assets	$ 459.6	410.9
Noncurrent Regulatory Liabilities	1,702.2	2,447.9
Ohio Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 7.7	7.2	7.3
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Noncurrent Regulatory Assets	$ 327.3	293
Noncurrent Regulatory Liabilities	1,044	1,020.9
Public Service Co Of Oklahoma [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 4.7	4.6	4.9
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Noncurrent Regulatory Assets	$ 653.7	1,037.4
Noncurrent Regulatory Liabilities	809.1	835.3
Southwestern Electric Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 6.4	6.4	6.7
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100%
Eligible Compensation Contribution by Employee Percentage	1%
Second Matching Contributions Provided Percentage	70%
Second Eligible Compensation Contribution by Employee Percentage	5%
Noncurrent Regulatory Assets	$ 1,042.4	1,005.3
Noncurrent Regulatory Liabilities	825.7	806.9
Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	3,883	4,892.2
Underfunded Benefit Obligation
Projected Benefit Obligation	4,072.7	5,187	5,544.5
Accumulated Benefit Obligation	3,883	4,892.2
Fair Value of Plan Assets	4,124.7	5,352.9	5,556.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	6.3
Components of Net Periodic Benefit Cost
Service Cost	123.1	129.2	111.9
Interest Cost	148.2	137.2	167.9
Expected Return on Plan Assets	(253.4)	(229.7)	(264.9)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	63	101.5	93.7
Settlements	0	0	0
Net Periodic Benefit Cost (Credit)	80.9	138.2	108.6
Capitalized Portion	(53.8)	(55.7)	(47)
Net Periodic Benefit Cost (Credit) Recognized in Expense	27.1	82.5	61.6
Pension Plans [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	369
2023	373.6
2024	368.8
2025	369.6
2026	364.3
Years 2027 to 2031, in Total	1,702.3
Pension Plans [Member] \| AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	317.9	394.7
Underfunded Benefit Obligation
Projected Benefit Obligation	334.1	419.8	453.2
Accumulated Benefit Obligation	317.9	394.7
Fair Value of Plan Assets	335.1	444.9	474
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0.4
Components of Net Periodic Benefit Cost
Service Cost	11.1	11.8	10
Interest Cost	12.1	11.2	13.9
Expected Return on Plan Assets	(21)	(19.5)	(22.7)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	5.2	8.3	7.8
Net Periodic Benefit Cost (Credit)	7.4	11.8	9
Capitalized Portion	(6.2)	(6.6)	(5.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	1.2	5.2	3.5
Pension Plans [Member] \| AEP Texas Inc. [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	35.4
2023	36.3
2024	35.2
2025	35
2026	32.6
Years 2027 to 2031, in Total	138.9
Pension Plans [Member] \| Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	470.4	597.4
Underfunded Benefit Obligation
Projected Benefit Obligation	485.7	621.7	670.8
Accumulated Benefit Obligation	470.4	597.4
Fair Value of Plan Assets	531.7	683.3	701.3
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0
Components of Net Periodic Benefit Cost
Service Cost	11.4	11.9	10.5
Interest Cost	17.5	16.4	20.3
Expected Return on Plan Assets	(32.3)	(29.1)	(33.6)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	7.4	12	11.2
Net Periodic Benefit Cost (Credit)	4	11.2	8.4
Capitalized Portion	(5)	(5.2)	(4.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(1)	6	3.9
Pension Plans [Member] \| Appalachian Power Co [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	43.7
2023	43.6
2024	42.5
2025	43
2026	41.8
Years 2027 to 2031, in Total	202.1
Pension Plans [Member] \| Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	445	576.4
Underfunded Benefit Obligation
Projected Benefit Obligation	466.8	612.1	653.3
Accumulated Benefit Obligation	445	576.4
Fair Value of Plan Assets	533.7	681.5	698.1
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0.1
Components of Net Periodic Benefit Cost
Service Cost	16.2	17.5	15.4
Interest Cost	17	16.2	19.7
Expected Return on Plan Assets	(32.4)	(28.9)	(33.3)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	7.1	11.7	10.8
Net Periodic Benefit Cost (Credit)	7.9	16.5	12.6
Capitalized Portion	(4.6)	(4.9)	(4.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	3.3	11.6	8.3
Pension Plans [Member] \| Indiana Michigan Power Co [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	38.1
2023	39.8
2024	40.7
2025	40.4
2026	41
Years 2027 to 2031, in Total	196.4
Pension Plans [Member] \| Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	344.2	440.3
Underfunded Benefit Obligation
Projected Benefit Obligation	363.6	470.7	510.3
Accumulated Benefit Obligation	344.2	440.3
Fair Value of Plan Assets	406.4	524.8	543.1
Components of Net Periodic Benefit Cost
Service Cost	11.2	11.4	9.7
Interest Cost	13.3	12.5	15.4
Expected Return on Plan Assets	(24.8)	(22.3)	(26.3)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	5.5	9.1	8.5
Net Periodic Benefit Cost (Credit)	5.2	10.7	7.3
Capitalized Portion	(6.1)	(6.2)	(5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(0.9)	4.5	2.3
Pension Plans [Member] \| Ohio Power Co [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	32.3
2023	31.9
2024	32.4
2025	32
2026	31.6
Years 2027 to 2031, in Total	146
Pension Plans [Member] \| Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	180.3	233.6
Underfunded Benefit Obligation
Projected Benefit Obligation	192.3	252.6	279.9
Accumulated Benefit Obligation	180.3	233.6
Fair Value of Plan Assets	218.5	286.2	299.8
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0.1
Components of Net Periodic Benefit Cost
Service Cost	7.4	8	7.3
Interest Cost	7	6.7	8.5
Expected Return on Plan Assets	(13.4)	(12.3)	(14.5)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	2.9	4.9	4.7
Net Periodic Benefit Cost (Credit)	3.9	7.3	6
Capitalized Portion	(3.2)	(3.4)	(2.8)
Net Periodic Benefit Cost (Credit) Recognized in Expense	0.7	3.9	3.2
Pension Plans [Member] \| Public Service Co Of Oklahoma [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	19.2
2023	18.9
2024	19
2025	19.2
2026	18.4
Years 2027 to 2031, in Total	81.1
Pension Plans [Member] \| Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	235.1	292.7
Underfunded Benefit Obligation
Projected Benefit Obligation	250.7	317.7	334.5
Accumulated Benefit Obligation	235.1	292.7
Fair Value of Plan Assets	231.3	308.3	326.9
Underfunded Status, Projected Benefit Obligation	(19.4)	(9.4)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0.1
Components of Net Periodic Benefit Cost
Service Cost	10.6	11.2	9.9
Interest Cost	9.1	8.5	10.2
Expected Return on Plan Assets	(14.6)	(13.5)	(15.7)
Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of Net Actuarial Loss	3.8	6.2	5.7
Net Periodic Benefit Cost (Credit)	8.9	12.4	10.1
Capitalized Portion	(4)	(4.1)	(3.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	4.9	8.3	6.7
Pension Plans [Member] \| Southwestern Electric Power Co [Member] \| Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	24.2
2023	25.1
2024	25.3
2025	25.5
2026	25.4
Years 2027 to 2031, in Total	107.9
Qualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	3,827.4	4,822.5
Underfunded Benefit Obligation
Accumulated Benefit Obligation	3,827.4	4,822.5
Qualified Pension Plans [Member] \| AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	315.4	391.4
Underfunded Benefit Obligation
Accumulated Benefit Obligation	315.4	391.4
Qualified Pension Plans [Member] \| Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	470.1	597
Underfunded Benefit Obligation
Accumulated Benefit Obligation	470.1	597
Qualified Pension Plans [Member] \| Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	443.8	575.2
Underfunded Benefit Obligation
Accumulated Benefit Obligation	443.8	575.2
Qualified Pension Plans [Member] \| Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	344.1	440
Underfunded Benefit Obligation
Accumulated Benefit Obligation	344.1	440
Qualified Pension Plans [Member] \| Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	179.1	232.1
Underfunded Benefit Obligation
Accumulated Benefit Obligation	179.1	232.1
Qualified Pension Plans [Member] \| Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	234	291.4
Underfunded Benefit Obligation
Accumulated Benefit Obligation	234	291.4
Nonqualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	55.6	69.7
Underfunded Benefit Obligation
Projected Benefit Obligation	61.5	78.4
Accumulated Benefit Obligation	55.6	69.7
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(61.5)	(78.4)
Underfunded Status, Accumulated Benefit Obligation	(55.6)	(69.7)
Nonqualified Pension Plans [Member] \| AEP Texas Inc. [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	2.5	3.3
Underfunded Benefit Obligation
Projected Benefit Obligation	2.7	3.6
Accumulated Benefit Obligation	2.5	3.3
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(2.7)	(3.6)
Underfunded Status, Accumulated Benefit Obligation	(2.5)	(3.3)
Nonqualified Pension Plans [Member] \| Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.3	0.4
Underfunded Benefit Obligation
Projected Benefit Obligation	0.6	0.8
Accumulated Benefit Obligation	0.3	0.4
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(0.6)	(0.8)
Underfunded Status, Accumulated Benefit Obligation	(0.3)	(0.4)
Nonqualified Pension Plans [Member] \| Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	1.2	1.2
Underfunded Benefit Obligation
Projected Benefit Obligation	1.6	1.9
Accumulated Benefit Obligation	1.2	1.2
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(1.6)	(1.9)
Underfunded Status, Accumulated Benefit Obligation	(1.2)	(1.2)
Nonqualified Pension Plans [Member] \| Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.1	0.3
Underfunded Benefit Obligation
Projected Benefit Obligation	0.3	0.7
Accumulated Benefit Obligation	0.1	0.3
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(0.3)	(0.7)
Underfunded Status, Accumulated Benefit Obligation	(0.1)	(0.3)
Nonqualified Pension Plans [Member] \| Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	1.2	1.5
Underfunded Benefit Obligation
Projected Benefit Obligation	1.5	1.9
Accumulated Benefit Obligation	1.2	1.5
Fair Value of Plan Assets	0	0
Underfunded Status, Projected Benefit Obligation	(1.5)	(1.9)
Underfunded Status, Accumulated Benefit Obligation	(1.2)	(1.5)
Nonqualified Pension Plans [Member] \| Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	1.1	1.3
Underfunded Benefit Obligation
Accumulated Benefit Obligation	1.1	1.3
Fair Value of Plan Assets	231.3	0
Underfunded Status, Accumulated Benefit Obligation	(3.8)	(1.3)
Other Postretirement Benefit Plans [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	872.6	1,041.3	1,210.9
Fair Value of Plan Assets	1,549.3	2,044.3	1,946.7
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	3.1
Components of Net Periodic Benefit Cost
Service Cost	7.4	9.5	10
Interest Cost	29.2	30.5	39.8
Expected Return on Plan Assets	(110)	(91.1)	(95.6)
Amortization of Prior Service Cost (Credit)	(71.4)	(70.9)	(69.8)
Amortization of Net Actuarial Loss	0	0	5.9
Settlements	0	0	0
Net Periodic Benefit Cost (Credit)	(144.8)	(122)	(109.7)
Capitalized Portion	(3.2)	(4.1)	(4.2)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(148)	(126.1)	(113.9)
Other Postretirement Benefit Plans [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	116
2023	117.6
2024	126.9
2025	127.4
2026	126.8
Years 2027 to 2031, in Total	604
Other Postretirement Benefit Plans [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0.2
2023	0.3
2024	0.3
2025	0.3
2026	0.3
Years 2027 to 2031, in Total	1.6
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	68.6	80.5	96.3
Fair Value of Plan Assets	128.3	168.8	162.3
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0.1
Components of Net Periodic Benefit Cost
Service Cost	0.5	0.7	0.8
Interest Cost	2.2	2.4	3.2
Expected Return on Plan Assets	(9.1)	(7.5)	(8)
Amortization of Prior Service Cost (Credit)	(6.1)	(6)	(5.9)
Amortization of Net Actuarial Loss	0	0	0.5
Net Periodic Benefit Cost (Credit)	(12.5)	(10.4)	(9.4)
Capitalized Portion	(0.3)	(0.4)	(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(12.8)	(10.8)	(9.8)
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	9.1
2023	9.5
2024	10.4
2025	10.6
2026	10.6
Years 2027 to 2031, in Total	48.5
Other Postretirement Benefit Plans [Member] \| AEP Texas Inc. [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0
2023	0
2024	0
2025	0
2026	0
Years 2027 to 2031, in Total	0
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	140.7	167.3	198.2
Fair Value of Plan Assets	228.6	302.3	293
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	1.6
Components of Net Periodic Benefit Cost
Service Cost	0.8	1	1
Interest Cost	4.7	4.9	6.6
Expected Return on Plan Assets	(16.3)	(13.5)	(14.4)
Amortization of Prior Service Cost (Credit)	(10.4)	(10.3)	(10.2)
Amortization of Net Actuarial Loss	0	0	0.9
Net Periodic Benefit Cost (Credit)	(21.2)	(17.9)	(16.1)
Capitalized Portion	(0.4)	(0.4)	(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(21.6)	(18.3)	(16.5)
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	19
2023	19.3
2024	20.5
2025	20.4
2026	20.3
Years 2027 to 2031, in Total	95.8
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0.1
2023	0.1
2024	0.1
2025	0.1
2026	0.1
Years 2027 to 2031, in Total	0.5
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	101.9	118.6	141.4
Fair Value of Plan Assets	190.5	248.7	238.2
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	1.3	1.4
Interest Cost	3.4	3.5	4.7
Expected Return on Plan Assets	(13.7)	(11.1)	(11.7)
Amortization of Prior Service Cost (Credit)	(9.7)	(9.6)	(9.5)
Amortization of Net Actuarial Loss	0	0	0.7
Net Periodic Benefit Cost (Credit)	(19.1)	(15.9)	(14.4)
Capitalized Portion	(0.3)	(0.4)	(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(19.4)	(16.3)	(14.8)
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	14.9
2023	15
2024	16.1
2025	16.3
2026	16.1
Years 2027 to 2031, in Total	75.1
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0
2023	0
2024	0
2025	0
2026	0
Years 2027 to 2031, in Total	0
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	88.9	104.9	126.4
Fair Value of Plan Assets	166.2	220	213
Components of Net Periodic Benefit Cost
Service Cost	0.6	0.8	0.9
Interest Cost	3	3	4.2
Expected Return on Plan Assets	(12)	(9.7)	(10.5)
Amortization of Prior Service Cost (Credit)	(7.1)	(7.2)	(7)
Amortization of Net Actuarial Loss	0	0	0.7
Net Periodic Benefit Cost (Credit)	(15.5)	(13.1)	(11.7)
Capitalized Portion	(0.3)	(0.4)	(0.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(15.8)	(13.5)	(12.2)
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	12.6
2023	12.6
2024	13.5
2025	13.4
2026	13.3
Years 2027 to 2031, in Total	62.3
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0
2023	0
2024	0
2025	0
2026	0
Years 2027 to 2031, in Total	0
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	45.7	54.4	64
Fair Value of Plan Assets	85.4	114	107.8
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0
Components of Net Periodic Benefit Cost
Service Cost	0.4	0.6	0.7
Interest Cost	1.5	1.6	2.1
Expected Return on Plan Assets	(6.1)	(5)	(5.2)
Amortization of Prior Service Cost (Credit)	(4.4)	(4.4)	(4.4)
Amortization of Net Actuarial Loss	0	0	0.3
Net Periodic Benefit Cost (Credit)	(8.6)	(7.2)	(6.5)
Capitalized Portion	(0.2)	(0.3)	(0.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(8.8)	(7.5)	(6.8)
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	6.7
2023	6.9
2024	7.4
2025	7.3
2026	7.1
Years 2027 to 2031, in Total	32.2
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0
2023	0
2024	0
2025	0
2026	0
Years 2027 to 2031, in Total	0
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member]
Underfunded Benefit Obligation
Projected Benefit Obligation	55.1	65.2	77.1
Fair Value of Plan Assets	103	136.6	129.9
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2022	0
Components of Net Periodic Benefit Cost
Service Cost	0.6	0.8	0.8
Interest Cost	1.8	1.9	2.5
Expected Return on Plan Assets	(7.3)	(6.1)	(6.3)
Amortization of Prior Service Cost (Credit)	(5.3)	(5.3)	(5.2)
Amortization of Net Actuarial Loss	0	0	0.4
Net Periodic Benefit Cost (Credit)	(10.2)	(8.7)	(7.8)
Capitalized Portion	(0.2)	(0.3)	(0.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(10.4)	$ (9)	$ (8.1)
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member] \| Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2022	7.5
2023	7.8
2024	8.5
2025	8.6
2026	8.5
Years 2027 to 2031, in Total	41.2
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member] \| Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2022	0
2023	0
2024	0
2025	0
2026	0
Years 2027 to 2031, in Total	$ 0

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		12 Months Ended
Business Segments (Details) - USD ($) $ in Millions		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Reportable Segment Information
Revenue from Contracts with Customers		$ 19,639.5		$ 16,792		$ 14,918.5
Sales to AEP Affiliates		0		0		0
Total Revenues		19,639.5		16,792		14,918.5
Loss on the Expected Sale of KPCo		363.3
Asset Impairments and Other Related Charges		48.8		11.6		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset		(37)		0		0
Gain (Loss) on Disposition of Assets		(116.3)
Utilities Operating Expense, Depreciation and Amortization		3,202.8		2,825.7		2,682.8
Allowance for Equity Funds Used During Construction		133.7		139.7		148.1
Interest Expense		1,396.1		1,199.1		1,165.7
Income Tax Expense/Benefit		5.4		115.5		40.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(109.4)		91.7		91.1
Net Income (Loss)		2,305.6		2,488.1		2,196.7
Gross Property Additions		7,879		6,426.8		6,246.3
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		97,021.4		90,225
Accumulated Depreciation and Amortization		23,682.3		21,920.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		73,339.1		68,304.1
Total Assets		93,403.3		87,668.7
Investments in Equity Method Investees		1,276.7		1,447.5		1,406.3
Long-term Debt Due Within One Year		2,486.4		2,353.8
Long-term Debt		34,314.6		32,203.8
Total Long-term Debt Outstanding		36,801		34,557.6
AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,651.7		1,410.9		1,232.7
Revenues from Related Parties, Net of Provisions for Refund		1,283.8		1,153.9		896.3
Sales to AEP Affiliates		1,354.5		1,171.5		954.6
Total Revenues		1,624.5		1,469.3		1,145.7
Utilities Operating Expense, Depreciation and Amortization		346.2		297.3		249
Interest Income		1.6		0.5		2.4
Allowance for Equity Funds Used During Construction		70.7		67.2		74
Interest Expense		162.7		141.2		127.8
Income Tax Expense/Benefit		169.1		144.1		106.7
Net Income (Loss)		594.2		591.7		423.4
Gross Property Additions		1,468.3		1,442.7		1,621.9
Balance Sheet Information
Property, Plant and Equipment, Gross, Period Increase (Decrease)		14,366.9		12,885.1
Accumulated Depreciation and Amortization		1,027		784.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		13,339.9		12,101
Total Assets		13,814.2		12,524.4
Long-term Debt Due Within One Year		60		104
Long-term Debt		4,722.8		4,239.9
Total Long-term Debt Outstanding		4,782.8		4,343.9
Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		11,292.8		9,852.2		8,753.2
Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		5,489.6		4,464.1		4,238.7
Transmission [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		354.9		317.8		265.4
Balance Sheet Information
Revenue from Contract with Customers, Net of Provisions for Refund, Including Assessed Tax		340.9		315.1		248.8
Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,448.9		2,108.3		1,621
Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		408.2		367.4		305.6
Total Revenues		360.3	[1],[2]	227.6	[3],[4]	61.5	[5],[6]
Other Revenues [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		(0.2)		0.3		0.6
Total Revenues		0	[7]	0	[8]	0	[9]
Reconciling Adjustments [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		0		0
Sales to AEP Affiliates		(1,603.8)		(1,461.5)		(1,328)
Total Revenues		(1,603.8)		(1,461.5)		(1,328)
Loss on the Expected Sale of KPCo		0
Asset Impairments and Other Related Charges		0		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset		0
Gain (Loss) on Disposition of Assets		0
Utilities Operating Expense, Depreciation and Amortization		0		0		0
Interest Expense		(112.8)		(18.7)		(42.1)
Income Tax Expense/Benefit		0		0		0
Equity Earnings (Loss) of Unconsolidated Subsidiaries		0		0		0
Net Income (Loss)		0		0		0
Gross Property Additions		(28.8)		(29.2)		(15.3)
Balance Sheet Information
Total Assets	[10]	(5,783)		(4,409.1)
Investments in Equity Method Investees		0		0
Reconciling Adjustments [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		0		0
Sales to AEP Affiliates		0		0		0
Total Revenues		0		0		0
Utilities Operating Expense, Depreciation and Amortization		0		0		0
Interest Income	[11]	(176.9)		(157.7)		(148.1)
Allowance for Equity Funds Used During Construction		0		0		0
Interest Expense	[11]	(176.9)		(157.7)		(148.1)
Income Tax Expense/Benefit		0		0		0
Net Income (Loss)		0		0		0
Gross Property Additions		0		0		0
Balance Sheet Information
Total Assets	[12]	(4,878.8)		(4,429.4)
Reconciling Adjustments [Member] \| Other Revenues [Member]
Reportable Segment Information
Total Revenues		(9.1)	[1],[2]	(10.7)	[3],[4]	(74.9)	[5],[6]
Reconciling Adjustments [Member] \| Other Revenues [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		0		0
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates		184.7		146.3		126.2
Total Revenues		11,477.5		9,998.5		8,879.4
Loss on the Expected Sale of KPCo		0
Asset Impairments and Other Related Charges		24.9		11.6
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset		(37)
Gain (Loss) on Disposition of Assets		0
Utilities Operating Expense, Depreciation and Amortization		2,007.2		1,747.6		1,600.5
Interest Expense		650.9		574.2		565
Income Tax Expense/Benefit		(93.8)		(11.2)		(7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries		1.4		3.4		2.9
Net Income (Loss)		1,296.2		1,116.7		1,064.5
Gross Property Additions		4,164.6		2,963.1		2,291.2
Balance Sheet Information
Total Assets		49,761.8		46,974.2
Investments in Equity Method Investees		10.1		33.5		37.1
Vertically Integrated Utilities [Member] \| Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		11,292.8		9,852.2		8,753.2
Vertically Integrated Utilities [Member] \| Other Revenues [Member]
Reportable Segment Information
Total Revenues		0.4	[1],[2]	(0.5)	[3],[4]	0	[5],[6]
Transmission and Distribution Companies [Member]
Reportable Segment Information
Sales to AEP Affiliates		22.4		28.8		107.2
Total Revenues		5,512		4,492.9		4,345.9
Loss on the Expected Sale of KPCo		0
Asset Impairments and Other Related Charges		0		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset		0
Gain (Loss) on Disposition of Assets		0
Utilities Operating Expense, Depreciation and Amortization		746.7		690.3		751.1
Interest Expense		328		300.9		289.2
Income Tax Expense/Benefit		116.9		77.5		29.7
Equity Earnings (Loss) of Unconsolidated Subsidiaries		0.6		0		0
Net Income (Loss)		595.7		543.4		496.4
Gross Property Additions		2,177.3		1,766		2,108.1
Balance Sheet Information
Total Assets		22,920.2		21,120.2
Investments in Equity Method Investees		3		2.5		2.1
Transmission and Distribution Companies [Member] \| Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		5,489.6		4,464.1		4,238.7
Transmission and Distribution Companies [Member] \| Other Revenues [Member]
Reportable Segment Information
Total Revenues		18.6	[1],[2]	19	[3],[4]	83	[5],[6]
AEP Transmission Holdco
Reportable Segment Information
Sales to AEP Affiliates		1,319.5		1,175.1		901.4
Total Revenues		1,677		1,526.2		1,198.8
Loss on the Expected Sale of KPCo		0
Asset Impairments and Other Related Charges		0		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset		0
Gain (Loss) on Disposition of Assets		0
Utilities Operating Expense, Depreciation and Amortization		355		306		257.6
Interest Expense		169.3		146.3		133.2
Income Tax Expense/Benefit		193.6		159.6		130.8
Equity Earnings (Loss) of Unconsolidated Subsidiaries		83.4		75		82.4
Net Income (Loss)		676.8		682		508.5
Gross Property Additions		1,470.8		1,468.6		1,649.3
Balance Sheet Information
Total Assets		15,215.8		13,873.3
Investments in Equity Method Investees		858.3		830.4		831.3
AEP Transmission Holdco \| Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		357.5		351.1		297.4
Generation and Marketing [Member]
Reportable Segment Information
Sales to AEP Affiliates		18		55.4		104.6
Total Revenues		2,466.9		2,163.7		1,725.6
Loss on the Expected Sale of KPCo		0
Asset Impairments and Other Related Charges		0		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset		0
Gain (Loss) on Disposition of Assets		(116.3)
Utilities Operating Expense, Depreciation and Amortization		93		80.9		72.8
Interest Expense		51.8		15.6		24
Income Tax Expense/Benefit		(83.1)		(48.8)		(108)
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(192.4)		(10.6)		3.2
Net Income (Loss)		274.5		210.2		216.9
Gross Property Additions		69.2		232.8		197
Balance Sheet Information
Total Assets		4,520.1		4,263.6
Investments in Equity Method Investees		337.6		487.8		467
Generation and Marketing [Member] \| Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,448.9		2,108.3		1,621
Generation and Marketing [Member] \| Other Revenues [Member]
Reportable Segment Information
Total Revenues		341.3	[1],[2]	209.1	[3],[4]	43.6	[5],[6]
All Other [Member]
Reportable Segment Information
Sales to AEP Affiliates	[13]	59.2		55.9		88.6
Total Revenues	[13]	109.9		72.2		96.8
Loss on the Expected Sale of KPCo	[13]	363.3
Asset Impairments and Other Related Charges	[13]	23.9		0
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	[13]	0
Gain (Loss) on Disposition of Assets	[13]	0
Utilities Operating Expense, Depreciation and Amortization	[13]	0.9		0.9		0.8
Interest Expense	[13]	308.9		180.8		196.4
Income Tax Expense/Benefit	[13]	(128.2)		(61.6)		(5)
Equity Earnings (Loss) of Unconsolidated Subsidiaries	[13]	(2.4)		23.9		2.6
Net Income (Loss)	[13]	(537.6)		(64.2)		(89.6)
Gross Property Additions	[13]	25.9		25.5		16
Balance Sheet Information
Total Assets	[13],[14]	6,768.4		5,846.5
Investments in Equity Method Investees	[13]	67.7		93.3		68.8
All Other [Member] \| Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers	[13]	50.7		16.3		8.2
Total Revenues		9.1	[1],[2]	10.7	[3],[4]	9.8	[5],[6]
State Transcos [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		1,283.8		1,153.9		896.3
Total Revenues		1,624.5		1,469.3		1,145.7
Utilities Operating Expense, Depreciation and Amortization		346.2		297.3		249
Interest Income		0.7		0.1		0.9
Allowance for Equity Funds Used During Construction		70.7		67.2		74
Interest Expense		162.5		141.2		127.8
Income Tax Expense/Benefit		169.1		144.1		106.5
Net Income (Loss)		594.2		591.5		422.3
Gross Property Additions		1,468.3		1,442.7		1,621.9
Balance Sheet Information
Total Assets		13,875.6		12,564.3
State Transcos [Member] \| Transmission [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		340.9		315.1		248.8
State Transcos [Member] \| Other Revenues [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		(0.2)		0.3		0.6
AEPTCo Parent [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		0		0		0
Total Revenues		0		0		0
Utilities Operating Expense, Depreciation and Amortization		0		0		0
Interest Income		177.8		158.1		149.6
Allowance for Equity Funds Used During Construction		0		0		0
Interest Expense		177.1		157.7		148.1
Income Tax Expense/Benefit		0		0		0.2
Net Income (Loss)	[15]	0		0.2		1.1
Gross Property Additions		0		0		0
Balance Sheet Information
Total Assets	[16]	4,817.4		4,389.5
AEPTCo Parent [Member] \| Transmission [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0		0		0
AEPTCo Parent [Member] \| Other Revenues [Member] \| AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		$ 0		$ 0		$ 0

[1]Amounts include affiliated and nonaffiliated revenues.[2]Generation & Marketing includes economic hedge activity.[3]Amounts include affiliated and nonaffiliated revenues.[4]Generation & Marketing includes economic hedge activity.[5]Amounts include affiliated and nonaffiliated revenues.[6]Generation & Marketing includes economic hedge activity.[7]Amounts include affiliated and nonaffiliated revenues.[8]Amounts include affiliated and nonaffiliated revenues.[9]Amounts include affiliated and nonaffiliated revenues.[10]Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.[11]Elimination of intercompany interest income/interest expense on affiliated debt arrangement.[12]Primarily relates to elimination of Notes Receivable from the State Transcos.[13]Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.[14]Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.[15]Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.[16]Primarily relates to Notes Receivable from the State Transcos.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, MWh in Millions, MMBTU in Millions		12 Months Ended
		Dec. 31, 2022 USD ($) MWh MMBTU gal		Dec. 31, 2021 USD ($) MWh MMBTU gal		Dec. 31, 2020 USD ($)
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 481,000,000		$ 263,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		348,800,000		200,400,000
Derivative Asset, Noncurrent		284,100,000		267,000,000
Total Assets		632,900,000		467,400,000
Current Risk Management Liabilities		145,200,000		75,500,000
Derivative Liability, Noncurrent		345,200,000		230,300,000
Total Liabilities		490,400,000		305,800,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		693,700,000	[1]	324,000,000		$ 116,900,000
Impact of Fair Value Hedges on the Balance Sheet
Carrying Amount of Hedged Asset (Liability)	[2],[3]	(855,500,000)		(952,300,000)
Cumulative Fair Value Hedging Adjustment in the Carrying Amount of the Hedged Asset (Liability)	[2],[3]	89,700,000		(8,500,000)
Impact of Cash Flow Hedges on the Balance Sheet
Gain (Loss) on Fair Value Hedging Instruments	[4]	(90,400,000)		(35,500,000)		41,100,000
Gain (Loss) on Fair Value Portion of Long Term Debt	[4]	90,400,000		35,500,000		(41,100,000)
Collateral Triggering Events
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		217,000,000		76,000,000
Derivatives and Hedging (Textuals)
Hedged Liability, Discontinued Fair Value Hedge, Cumulative Increase (Decrease)		(38,000,000)		(46,000,000)
Notional Amount of a Discontinued Hedge		500,000,000
Deferred (Gain) Loss on Discontinuation of Fair Value Hedge		57,000,000
Credit Downgrade Trigger Exposure		2,000,000		9,000,000
Fair Value Of Derivative Liabilities Subject To Cross Acceleration Provisions		127,000,000		40,000,000
AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2,800,000	[1]	2,000,000		(1,000,000)
Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		69,100,000		42,000,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		88,600,000	[1]	55,300,000		21,300,000
Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		15,200,000		3,300,000
Current Risk Management Liabilities		0		5,000,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		19,600,000	[1]	(18,200,000)		12,000,000
Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Liabilities		1,800,000		6,700,000
Derivative Liability, Noncurrent		37,900,000		85,800,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		57,800,000	[1]	11,100,000		5,000,000
Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		25,300,000		12,100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		103,700,000	[1]	46,000,000		38,600,000
Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		16,400,000		9,800,000
Current Risk Management Liabilities		1,400,000		2,100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		77,700,000	[1]	41,500,000		21,000,000
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[5]	315,400,000	[6]	245,800,000	[7]
Total Liabilities	[5]	339,800,000	[6]	254,800,000	[7]
Risk Management Contracts [Member] \| AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Total Assets				0
Risk Management Contracts [Member] \| Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[5],[8]	69,100,000		42,000,000
Total Liabilities	[5],[8]	3,500,000		800,000
Risk Management Contracts [Member] \| Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[5],[8]	15,400,000		3,300,000
Total Liabilities	[5],[8]	0		5,000,000
Risk Management Contracts [Member] \| Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[5],[8]	0		0
Total Liabilities	[5],[8]	39,700,000		92,500,000
Risk Management Contracts [Member] \| Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets		25,300,000		12,100,000	[5],[8]
Total Liabilities	[5],[8]	1,600,000		3,700,000
Risk Management Contracts [Member] \| Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[5],[8]	16,400,000		10,900,000
Total Liabilities	[5],[8]	1,400,000		2,100,000
Commodity [Member]
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		223,500,000		163,700,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		$ 119,900,000		106,700,000
Derivatives and Hedging (Textuals)
Maximum Length of Time Hedged in Price Risk Cash Flow Hedge		99 months
Cross Default Provisions Maximum Third Party Obligation Amount		$ 50,000,000
Cross Acceleration Provisions Maximum Third Party Obligation Amount		50,000,000
Commodity [Member] \| Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	965,400,000		520,900,000
Derivative Asset, Noncurrent	[9]	565,600,000		370,500,000
Total Assets	[9]	1,531,000,000		891,400,000
Current Risk Management Liabilities	[9]	663,800,000		397,200,000
Derivative Liability, Noncurrent	[9]	412,000,000		243,900,000
Total Liabilities	[9]	1,075,800,000		641,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	455,200,000	[10]	250,300,000
Commodity [Member] \| Risk Management Contracts [Member] \| AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	0		600,000
Derivative Asset, Noncurrent	[9]	0		0
Total Assets	[9]	0		600,000
Current Risk Management Liabilities	[9]	0		0
Derivative Liability, Noncurrent	[9]	0		0
Total Liabilities	[9]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	0		600,000
Commodity [Member] \| Risk Management Contracts [Member] \| Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	69,300,000		47,500,000
Derivative Asset, Noncurrent	[9]	700,000		200,000
Total Assets	[9]	70,000,000		47,700,000
Current Risk Management Liabilities	[9]	4,100,000		7,200,000
Derivative Liability, Noncurrent	[9]	700,000		200,000
Total Liabilities	[9]	4,800,000		7,400,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	65,200,000	[10]	40,300,000
Commodity [Member] \| Risk Management Contracts [Member] \| Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	16,000,000		11,100,000
Derivative Asset, Noncurrent	[9]	500,000		200,000
Total Assets	[9]	16,500,000		11,300,000
Current Risk Management Liabilities	[9]	900,000		14,800,000
Derivative Liability, Noncurrent	[9]	300,000		200,000
Total Liabilities	[9]	1,200,000		15,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	15,300,000	[10]	(3,700,000)
Commodity [Member] \| Risk Management Contracts [Member] \| Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	0		500,000
Derivative Asset, Noncurrent	[9]	0		0
Total Assets	[9]	0		500,000
Current Risk Management Liabilities	[9]	2,100,000		6,700,000
Derivative Liability, Noncurrent	[9]	37,900,000		85,800,000
Total Liabilities	[9]	40,000,000		92,500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(40,000,000)	[10]	(92,000,000)
Commodity [Member] \| Risk Management Contracts [Member] \| Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	24,100,000		12,400,000
Derivative Asset, Noncurrent	[9]	0		0
Total Assets	[9]	24,100,000		12,400,000
Current Risk Management Liabilities	[9]	2,100,000		3,700,000
Derivative Liability, Noncurrent	[9]	0		0
Total Liabilities	[9]	2,100,000		3,700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	22,000,000	[10]	8,700,000
Commodity [Member] \| Risk Management Contracts [Member] \| Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	16,800,000		10,100,000
Derivative Asset, Noncurrent	[9]	0		1,100,000
Total Assets	[9]	16,800,000		11,200,000
Current Risk Management Liabilities	[9]	2,000,000		2,100,000
Derivative Liability, Noncurrent	[9]	0		0
Total Liabilities	[9]	2,000,000		2,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	14,800,000	[10]	9,100,000
Commodity [Member] \| Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	212,200,000		176,000,000
Derivative Asset, Noncurrent	[9]	148,900,000		89,100,000
Total Assets	[9]	361,100,000		265,100,000
Current Risk Management Liabilities	[9]	60,400,000		40,900,000
Derivative Liability, Noncurrent	[9]	17,400,000		16,700,000
Total Liabilities	[9]	77,800,000		57,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	283,300,000	[10]	207,500,000
Interest Rate [Member]
Commodity
Derivative, Notional Amount		1,650,000,000		950,000,000
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		300,000		(21,300,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		$ 300,000		(3,300,000)
Derivatives and Hedging (Textuals)
Maximum Length of Time Hedged in Price Risk Cash Flow Hedge		96 months
Interest Rate [Member] \| AEP Texas Inc. [Member]
Commodity
Derivative, Notional Amount		$ 0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(300,000)		(1,300,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(200,000)		(1,100,000)
Interest Rate [Member] \| Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		6,700,000		7,500,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		800,000		800,000
Interest Rate [Member] \| Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(5,100,000)		(6,700,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(600,000)		(1,600,000)
Interest Rate [Member] \| Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate [Member] \| Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		200,000,000		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		1,300,000		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		100,000		0
Interest Rate [Member] \| Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		1,100,000		1,200,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		200,000		100,000
Interest Rate [Member] \| Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	1,800,000		1,200,000
Derivative Asset, Noncurrent	[9]	14,300,000		0
Total Assets	[9]	16,100,000		1,200,000
Current Risk Management Liabilities	[9]	41,400,000		0
Derivative Liability, Noncurrent	[9]	91,100,000		38,100,000
Total Liabilities	[9]	132,500,000		38,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(116,400,000)		(36,900,000)
Interest Rate [Member] \| Hedging Contracts [Member] \| Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	1,600,000
Derivative Asset, Noncurrent	[9]	0
Total Assets	[9]	1,600,000
Current Risk Management Liabilities	[9]	0
Derivative Liability, Noncurrent	[9]	0
Total Liabilities	[9]	0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	1,600,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		1,179,400,000		698,100,000
Derivative Asset, Noncurrent		728,800,000		459,600,000
Total Assets		1,908,200,000		1,157,700,000
Current Risk Management Liabilities		765,600,000		438,100,000
Derivative Liability, Noncurrent		520,500,000		298,700,000
Total Liabilities		1,286,100,000		736,800,000
Total MTM Derivative Contract Net Assets (Liabilities)		622,100,000	[10]	420,900,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] \| Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		25,700,000
Derivative Asset, Noncurrent		0
Total Assets		25,700,000
Current Risk Management Liabilities		2,100,000
Derivative Liability, Noncurrent		0
Total Liabilities		2,100,000
Total MTM Derivative Contract Net Assets (Liabilities)		23,600,000
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	(830,600,000)		(497,700,000)
Derivative Asset, Noncurrent	[11]	(444,700,000)		(192,600,000)
Total Assets	[11]	(1,275,300,000)		(690,300,000)
Current Risk Management Liabilities	[11]	(620,400,000)		(362,600,000)
Derivative Liability, Noncurrent	[11]	(175,300,000)		(68,400,000)
Total Liabilities	[11]	(795,700,000)		(431,000,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	(479,600,000)	[10]	(259,300,000)
Gross Amounts Offset in the Statement of Financial Position [Member] \| AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	0		(600,000)
Derivative Asset, Noncurrent	[11]	0		0
Total Assets	[11]	0		(600,000)
Current Risk Management Liabilities	[11]	0		0
Derivative Liability, Noncurrent	[11]	0		0
Total Liabilities	[11]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	0		(600,000)
Gross Amounts Offset in the Statement of Financial Position [Member] \| Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	(200,000)		(5,500,000)
Derivative Asset, Noncurrent	[11]	(700,000)		(200,000)
Total Assets	[11]	(900,000)		(5,700,000)
Current Risk Management Liabilities	[11]	(500,000)		(6,400,000)
Derivative Liability, Noncurrent	[11]	(600,000)		(200,000)
Total Liabilities	[11]	(1,100,000)		(6,600,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	200,000		900,000
Gross Amounts Offset in the Statement of Financial Position [Member] \| Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	(800,000)		(7,800,000)
Derivative Asset, Noncurrent	[11]	(300,000)		(200,000)
Total Assets	[11]	(1,100,000)		(8,000,000)
Current Risk Management Liabilities	[11]	(900,000)		(9,800,000)
Derivative Liability, Noncurrent	[11]	(300,000)		(200,000)
Total Liabilities	[11]	(1,200,000)		(10,000,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	100,000		2,000,000
Gross Amounts Offset in the Statement of Financial Position [Member] \| Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	0		(500,000)
Derivative Asset, Noncurrent	[11]	0		0
Total Assets	[11]	0		(500,000)
Current Risk Management Liabilities	[11]	(300,000)		0
Derivative Liability, Noncurrent	[11]	0		0
Total Liabilities	[11]	(300,000)		0
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	300,000	[10]	(500,000)
Gross Amounts Offset in the Statement of Financial Position [Member] \| Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	(400,000)		(300,000)
Derivative Asset, Noncurrent	[11]	0		0
Total Assets	[11]	(400,000)		(300,000)
Current Risk Management Liabilities	[11]	(500,000)		0
Derivative Liability, Noncurrent	[11]	0		0
Total Liabilities	[11]	(500,000)		0
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	100,000		(300,000)
Gross Amounts Offset in the Statement of Financial Position [Member] \| Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	(400,000)		(300,000)
Derivative Asset, Noncurrent	[11]	0		0
Total Assets	[11]	(400,000)		(300,000)
Current Risk Management Liabilities	[11]	(600,000)		0
Derivative Liability, Noncurrent	[11]	0		0
Total Liabilities	[11]	(600,000)		0
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	200,000	[10]	(300,000)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	348,800,000		200,400,000
Derivative Asset, Noncurrent	[12]	284,100,000		267,000,000
Total Assets	[12]	632,900,000		467,400,000
Current Risk Management Liabilities	[12]	145,200,000		75,500,000
Derivative Liability, Noncurrent	[12]	345,200,000		230,300,000
Total Liabilities	[12]	490,400,000		305,800,000
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	142,500,000		161,600,000
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	[12]	0		0
Derivative Asset, Noncurrent	[12]	0		0
Total Assets	[12]	0		0
Current Risk Management Liabilities	[12]	0		0
Derivative Liability, Noncurrent	[12]	0		0
Total Liabilities	[12]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	0		0
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	[12]	69,100,000		42,000,000
Derivative Asset, Noncurrent	[12]	0		0
Total Assets	[12]	69,100,000		42,000,000
Current Risk Management Liabilities	[12]	3,600,000		800,000
Derivative Liability, Noncurrent	[12]	100,000		0
Total Liabilities	[12]	3,700,000		800,000
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	65,400,000	[10]	41,200,000
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	[12]	15,200,000		3,300,000
Derivative Asset, Noncurrent	[12]	200,000		0
Total Assets	[12]	15,400,000		3,300,000
Current Risk Management Liabilities	[12]	0		5,000,000
Derivative Liability, Noncurrent	[12]	0		0
Total Liabilities	[12]	0		5,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	15,400,000	[10]	(1,700,000)
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	[12]	0		0
Derivative Asset, Noncurrent	[12]	0		0
Total Assets	[12]	0		0
Current Risk Management Liabilities	[12]	1,800,000		6,700,000
Derivative Liability, Noncurrent	[12]	37,900,000		85,800,000
Total Liabilities	[12]	39,700,000		92,500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	(39,700,000)	[10]	(92,500,000)
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	[12]	25,300,000		12,100,000
Derivative Asset, Noncurrent	[12]	0		0
Total Assets	[12]	25,300,000		12,100,000
Current Risk Management Liabilities	[12]	1,600,000		3,700,000
Derivative Liability, Noncurrent	[12]	0		0
Total Liabilities	[12]	1,600,000		3,700,000
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	23,700,000	[10]	8,400,000
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	[12]	16,400,000		9,800,000
Derivative Asset, Noncurrent	[12]	0		1,100,000
Total Assets	[12]	16,400,000		10,900,000
Current Risk Management Liabilities	[12]	1,400,000		2,100,000
Derivative Liability, Noncurrent	[12]	0		0
Total Liabilities	[12]	1,400,000		2,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	$ 15,000,000	[10]	$ 8,800,000
Power [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		226.8		287.9
Power [Member] \| AEP Texas Inc. [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		0		0
Power [Member] \| Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		17.9		33.1
Power [Member] \| Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		4.2		13.6
Power [Member] \| Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		2.5		2.7
Power [Member] \| Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		2.9		11.9
Power [Member] \| Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MWh		2.2		3.4
Natural Gas [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		77.1		34.1
Natural Gas [Member] \| AEP Texas Inc. [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		0		0
Natural Gas [Member] \| Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		1.9		0
Natural Gas [Member] \| Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		0		0
Natural Gas [Member] \| Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		0		0
Natural Gas [Member] \| Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		1.9		1.3
Natural Gas [Member] \| Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount \| MMBTU		2.1		5.1
Heating Oil and Gasoline [Member]
Commodity
Derivative, Volume Notional Amount \| gal		6.9		7.4
Heating Oil and Gasoline [Member] \| AEP Texas Inc. [Member]
Commodity
Derivative, Volume Notional Amount \| gal		1.9		1.9
Heating Oil and Gasoline [Member] \| Appalachian Power Co [Member]
Commodity
Derivative, Volume Notional Amount \| gal		1		1.1
Heating Oil and Gasoline [Member] \| Indiana Michigan Power Co [Member]
Commodity
Derivative, Volume Notional Amount \| gal		0.7		0.7
Heating Oil and Gasoline [Member] \| Ohio Power Co [Member]
Commodity
Derivative, Volume Notional Amount \| gal		1.4		1.5
Heating Oil and Gasoline [Member] \| Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Volume Notional Amount \| gal		0.9		0.8
Heating Oil and Gasoline [Member] \| Southwestern Electric Power Co [Member]
Commodity
Derivative, Volume Notional Amount \| gal		1		1
Interest Rate Contract [Member]
Commodity
Derivative, Notional Amount		$ 99,900,000		$ 116,500,000
Interest Rate Contract [Member] \| AEP Texas Inc. [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] \| Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] \| Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] \| Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] \| Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] \| Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		11,100,000		(600,000)		800,000
Vertically Integrated Utilities Revenues [Member] \| AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] \| Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] \| Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] \| Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		313,800,000		169,100,000		9,500,000
Generation and Marketing Revenues [Member] \| AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] \| Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] \| Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] \| Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member] \| AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member] \| Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		500,000		(500,000)		400,000
Electric Generation, Transmission and Distribution Revenues [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		10,600,000		(100,000)		100,000
Electric Generation, Transmission and Distribution Revenues [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		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
Electric Generation, Transmission and Distribution Revenues [Member] \| Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		100,000
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		5,000,000		2,000,000		1,400,000
Purchased Electricity for Resale [Member] \| AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Purchased Electricity for Resale [Member] \| Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		4,500,000		1,800,000		1,200,000
Purchased Electricity for Resale [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		0		100,000
Purchased Electricity for Resale [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Purchased Electricity for Resale [Member] \| Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		200,000		0		0
Purchased Electricity for Resale [Member] \| Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		4,800,000		2,800,000		(2,000,000)
Other Operation Expense [Member] \| AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,500,000		800,000		(600,000)
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		400,000		300,000		(200,000)
Other Operation Expense [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		500,000		300,000		(200,000)
Other Operation Expense [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		800,000		500,000		(300,000)
Other Operation Expense [Member] \| Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		600,000		300,000		(200,000)
Other Operation Expense [Member] \| Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		800,000		400,000		(300,000)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6,700,000		3,400,000		(2,900,000)
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		1,800,000		1,000,000		(800,000)
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		900,000		500,000		(400,000)
Maintenance Expense [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		600,000		300,000		(300,000)
Maintenance Expense [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,200,000		600,000		(500,000)
Maintenance Expense [Member] \| Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		800,000		400,000		(300,000)
Maintenance Expense [Member] \| Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,100,000		500,000		(400,000)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	52,600,000		(9,100,000)		(4,800,000)
Regulatory Assets [Member] \| AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	100,000		0		0
Regulatory Assets [Member] \| Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(100,000)		(2,700,000)		0
Regulatory Assets [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(800,000)		(14,800,000)		(100,000)
Regulatory Assets [Member] \| Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	52,100,000		10,000,000		(6,600,000)
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	[13]	3,600,000		(3,600,000)		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	[13]	(2,100,000)		3,600,000		1,400,000
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	299,700,000		156,400,000		114,900,000
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	[13]	(600,000)		200,000		400,000
Regulatory Liabilities [Member] \| Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	82,400,000		55,900,000		20,300,000
Regulatory Liabilities [Member] \| Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	8,600,000		(3,900,000)		12,400,000
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	[13]	3,700,000		0		12,400,000
Regulatory Liabilities [Member] \| Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	98,500,000		48,900,000		39,100,000
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	[13]	$ 77,900,000		$ 37,000,000		$ 20,200,000

[1]Increase in amounts for the year ended December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.[2]Amounts include $(38) million and $(46) million as of December 31, 2022 and 2021, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.[3]Amounts included on the Balance Sheet within Current and Noncurrent Liabilities line items Long-term Debt Due within One Year and Long-term Debt, respectively.[4]Gain (Loss) is included in Interest Expense on the statements of income.[5]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.”[6]The December 31, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(7) million in 2023; Level 2 matures $182 million in 2023, $134 million in periods 2024-2026, $10 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $128 million in 2023, $6 million in periods 2024-2026, $6 million in periods 2027-2028 and $(5) million in periods 2029-2033. Risk management commodity contracts are substantially comprised of power contracts.[7]The December 31, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025; $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts.[8]Substantially comprised of power contracts for the Registrant Subsidiaries.[9]Derivative instruments within these categories are disclosed as 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.”[10]Increase in amounts as of December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.[11]Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”[12]All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.[13]Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 36,801	$ 34,557.6
Long-term Debt, Fair Value	[1]	32,915.9	38,789.3
Other Temporary Investments
Cost		223.6	232
Gross Unrealized Gains		19.4	36.4
Gross Unrealized Losses		8.3	0
Fair Value		234.7	268.4
Debt and Equity Securities Within Other Temporary Investments
Proceeds From Investment Sales		30.2	15	$ 50.9
Purchases of Investments		18.8	26.9	41.6
Gross Realized Gains on Investment Sales		6.1	3.6	3.8
Gross Realized Losses on Investment Sales		1.3	0	0.2
Nuclear Trust Fund Investments
Fair Value		3,341.2	3,867
Contractual Maturities, Fair Value of Debt Securities
Fair Value		3,341.2	3,867
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		1,467.3	1,974.7
Other-Than-Temporary Impairments		(28.5)	(10.1)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,713.6	1,886.4	1,593.4
Purchases of Investments		2,765.4	1,928.2	1,637.2
Gross Realized Gains on Investment Sales		52.4	103.2	26.4
Gross Realized Losses on Investment Sales		42.6	16.5	26.1
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		365.2
After 1 year through 5 years		425.4
After 5 years through 10 years		203
After 10 years		195.1
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,200	1,200
Adjusted Cost of Domestic Equity Securities		654	641
AEP Texas Inc. [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		5,657.8	5,180.8
Long-term Debt, Fair Value		5,045.8	5,663.8
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,782.8	4,343.9
Long-term Debt, Fair Value		3,940.5	4,968.2
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		5,410.5	4,938.9
Long-term Debt, Fair Value		5,079.2	6,037.1
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,260.8	3,195
Long-term Debt, Fair Value		2,929	3,748
Nuclear Trust Fund Investments
Fair Value		3,341.2	3,867
Contractual Maturities, Fair Value of Debt Securities
Fair Value		3,341.2	3,867
Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		1,467.3	1,974.7
Other-Than-Temporary Impairments		(28.5)	(10.1)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,713.6	1,886.4	1,593.4
Purchases of Investments		2,765.4	1,928.2	1,637.2
Gross Realized Gains on Investment Sales		52.4	103.2	26.4
Gross Realized Losses on Investment Sales		42.6	16.5	$ 26.1
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		365.2
After 1 year through 5 years		425.4
After 5 years through 10 years		203
After 10 years		195.1
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,200	1,200
Adjusted Cost of Domestic Equity Securities		654	641
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,970.3	2,968.5
Long-term Debt, Fair Value		2,516.6	3,437.5
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,912.8	1,913.5
Long-term Debt, Fair Value		1,635.8	2,163.7
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,391.6	3,395.2
Long-term Debt, Fair Value		2,870.9	3,792.9
Cash [Member]
Other Temporary Investments
Cost	[2]	47.1	48
Gross Unrealized Gains	[2]	0	0
Gross Unrealized Losses	[2]	0	0
Fair Value	[2]	47.1	48
Other Cash Deposits [Member]
Other Temporary Investments
Cost		9	10
Gross Unrealized Gains		0	0
Gross Unrealized Losses		0	0
Fair Value	[3]	9	10
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[4]	152.4	154.3
Gross Unrealized Gains	[4]	0	0.5
Gross Unrealized Losses	[4]	(8.3)	0
Fair Value	[4]	144.1	154.8
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		15.1	19.7
Gross Unrealized Gains		19.4	35.9
Gross Unrealized Losses		0	0
Fair Value		34.5	55.6
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,188.7	1,240.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,188.7	1,240.4
Fixed Income Funds [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		(10)	73.4
Other-Than-Temporary Impairments		(28.5)	(10.1)
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		1,188.7	1,240.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,188.7	1,240.4
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		(10)	73.4
Other-Than-Temporary Impairments		(28.5)	(10.1)
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	2,131.3	2,541.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	2,131.3	2,541.9
Domestic [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities		1,500	1,900
Unrealized Loss on Securities		6	4
Nuclear Trust Fund Investments
Gross Unrealized Gains	[6]	1,477.3	1,901.3
Other-Than-Temporary Impairments		0	0
Domestic [Member] \| Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	2,131.3	2,541.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	2,131.3	2,541.9
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities		1,500	1,900
Unrealized Loss on Securities		6	4
Nuclear Trust Fund Investments
Gross Unrealized Gains	[6]	1,477.3	1,901.3
Other-Than-Temporary Impairments		0	0
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	21.2	84.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	21.2	84.7
Cash and Cash Equivalents [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0	0
Other-Than-Temporary Impairments		0	0
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	21.2	84.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	21.2	84.7
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0	0
Other-Than-Temporary Impairments		0	0
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		1,123.8	1,156.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,123.8	1,156.4
US Government Agencies Debt Securities [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		(3.1)	66.3
Other-Than-Temporary Impairments		(18.8)	(7.9)
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		1,123.8	1,156.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,123.8	1,156.4
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		(3.1)	66.3
Other-Than-Temporary Impairments		(18.8)	(7.9)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		61.6	76.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		61.6	76.7
Corporate Debt [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		(7)	6.7
Other-Than-Temporary Impairments		(9.6)	(2.1)
Corporate Debt [Member] \| Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		61.6	76.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		61.6	76.7
Corporate Debt [Member] \| Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		(7)	6.7
Other-Than-Temporary Impairments		(9.6)	(2.1)
State and Local Jurisdiction
Nuclear Trust Fund Investments
Fair Value		3.3	7.3
Contractual Maturities, Fair Value of Debt Securities
Fair Value		3.3	7.3
State and Local Jurisdiction \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.1	0.4
Other-Than-Temporary Impairments		(0.1)	(0.1)
State and Local Jurisdiction \| Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		3.3	7.3
Contractual Maturities, Fair Value of Debt Securities
Fair Value		3.3	7.3
State and Local Jurisdiction \| Indiana Michigan Power Co [Member] \| Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.1	0.4
Other-Than-Temporary Impairments		(0.1)	(0.1)
Equity units [Member]
Book Values and Fair Values of Long - term Debt
Long-term Debt, Fair Value		$ 877	$ 1,700

[1]The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $877 million and $1.7 billion as of December 31, 2022 and 2021, respectively. See “Equity Units” section of Note 14 for additional information.[2]Primarily represents amounts held for the repayment of debt.[3]Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.[4]Primarily short and intermediate maturities which may be sold and do not contain maturity dates.[5]Amounts represent publicly-traded equity securities and equity-based mutual funds.[6]Amount reported as Gross Unrealized Gains includes unrealized gains of $1.5 billion and $1.9 billion and unrealized losses of $6 million and $4 million as of December 31, 2022 and 2021, respectively.[7]Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Fair Value Financial Assets Lia

Fair Value Financial Assets Liabilities (Details) - USD ($)		12 Months Ended
Fair Value Financial Assets Liabilities (Details) - USD ($)		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Assets, Fair Value Disclosure
Other Temporary Investments		$ 234,700,000		$ 268,400,000
Risk Management Assets
Derivative Assets		632,900,000		467,400,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		3,341,200,000		3,867,000,000
Total Assets		4,208,800,000		4,646,500,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		490,400,000		305,800,000
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		103,100,000		113,300,000		$ 109,900,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	69,500,000		48,600,000		39,500,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	(34,900,000)		(45,200,000)		35,300,000
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[3]	9,600,000		24,200,000		13,800,000
Settlements		(154,600,000)		(89,000,000)		(113,100,000)
Transfers into Level 3	[4],[5]	1,700,000		(3,800,000)		(3,800,000)
Transfers out of Level 3	[5]	100,000		(34,400,000)		5,600,000
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	165,900,000		89,400,000		26,100,000
Ending Balance		160,400,000		103,100,000		113,300,000
Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		9,000,000		10,000,000
Risk Management Assets
Derivative Assets		(1,264,300,000)		(685,600,000)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9,900,000		7,000,000
Total Assets		(1,245,400,000)		(668,600,000)
Liabilities, Fair Value Disclosure
Derivative Liabilities		(784,700,000)		(426,300,000)
Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		225,700,000		258,400,000
Risk Management Assets
Derivative Assets		15,000,000		7,400,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,142,600,000		2,619,600,000
Total Assets		2,383,300,000		2,914,200,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		21,800,000		5,300,000
Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Risk Management Assets
Derivative Assets		1,541,100,000		893,700,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,188,700,000		1,240,400,000
Total Assets		2,729,800,000		2,149,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		1,072,600,000		578,000,000
Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Risk Management Assets
Derivative Assets		341,100,000		251,900,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		341,100,000		251,900,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		180,700,000		148,800,000
2022 [Member] \| Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				1,000,000
2022 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				42,000,000
2022 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				82,000,000
2023 [Member] \| Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(7,000,000)
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		182,000,000
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		128,000,000
2023 - 2025 [Member] \| Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				1,000,000
2023 - 2025 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				109,000,000
2023 - 2025 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				10,000,000
2024 - 2026 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		134,000,000
2024 - 2026 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		6,000,000
2026 - 2027 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				10,000,000
2026 - 2027 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				9,000,000
2027-2028 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		10,000,000
2027-2028 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		6,000,000
2028 - 2033 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				3,000,000
2028 - 2033 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities				(17,000,000)
2029 - 2033 [Member] \| Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1,000,000
2029 - 2033 [Member] \| Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity Of Net Fair Value Of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(5,000,000)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets	[7]	315,400,000	[8]	245,800,000	[9]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	339,800,000	[8]	254,800,000	[9]
Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[7]	(1,211,500,000)	[8]	(643,900,000)	[9]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	(731,900,000)	[8]	(384,600,000)	[9]
Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[7]	15,000,000	[8]	7,400,000	[9]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	21,800,000	[8]	5,300,000	[9]
Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[7]	1,197,500,000	[8]	649,600,000	[9]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	870,900,000	[8]	485,900,000	[9]
Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[7]	314,400,000	[8]	232,700,000	[9]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	179,000,000	[8]	148,200,000	[9]
Energy Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		204,000,000		164,400,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		167,400,000		135,300,000
Energy Contracts [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	2.91		10.30
Energy Contracts [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	187.34		76.70
Energy Contracts [Member] \| Level 3 [Member] \| Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	49.14		37.11
Natural Gas Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				3,600,000
Liabilities, Fair Value Disclosure
Derivative Liabilities				0
Natural Gas Contracts [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[12]			3.11
Natural Gas Contracts [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[12]			4.02
Natural Gas Contracts [Member] \| Level 3 [Member] \| Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[11],[12]			3.47
FTRs [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		137,100,000		83,900,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		13,300,000		13,500,000
FTRs [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(36.45)		(23.93)
FTRs [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	20.72		26.38
FTRs [Member] \| Level 3 [Member] \| Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	1.18		0.86
Commodity Hedges [Member]
Risk Management Assets
Derivative Assets	[7]	306,500,000		220,400,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	23,200,000		12,900,000
Commodity Hedges [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[7]	(52,800,000)		(41,700,000)
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	(52,800,000)		(41,700,000)
Commodity Hedges [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[7]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	0		0
Commodity Hedges [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[7]	332,600,000		242,900,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	74,300,000		54,000,000
Commodity Hedges [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[7]	26,700,000		19,200,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7]	1,700,000		600,000
Interest Rate Foreign Currency Hedges [Member]
Risk Management Assets
Derivative Assets		11,000,000
Interest Rate Foreign Currency Hedges [Member] \| Other [Member]
Risk Management Assets
Derivative Assets		0
Interest Rate Foreign Currency Hedges [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets		0
Interest Rate Foreign Currency Hedges [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets		11,000,000
Interest Rate Foreign Currency Hedges [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		0
Fair Value Hedges [Member]
Risk Management Assets
Derivative Assets				1,200,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		127,400,000		38,100,000
Fair Value Hedges [Member] \| Other [Member]
Risk Management Assets
Derivative Assets				0
Liabilities, Fair Value Disclosure
Derivative Liabilities		0		0
Fair Value Hedges [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets				0
Liabilities, Fair Value Disclosure
Derivative Liabilities		0		0
Fair Value Hedges [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets				1,200,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		127,400,000		38,100,000
Fair Value Hedges [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				0
Liabilities, Fair Value Disclosure
Derivative Liabilities		0		0
Other Investments [Member]
Risk Management Assets
Derivative Assets	[13]			43,700,000
Other Investments [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[13]			0
Other Investments [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[13]			28,800,000
Other Investments [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[13]			14,900,000
Other Investments [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[13]			0
AEP Texas Inc. [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		32,700,000		30,400,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				30,400,000
AEP Texas Inc. [Member] \| Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				(600,000)
AEP Texas Inc. [Member] \| Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		32,700,000		30,400,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				30,400,000
AEP Texas Inc. [Member] \| Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				600,000
AEP Texas Inc. [Member] \| Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets				0
AEP Texas Inc. [Member] \| Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets				0
AEP Texas Inc. [Member] \| Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets				(600,000)
AEP Texas Inc. [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets				0
AEP Texas Inc. [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets				600,000
AEP Texas Inc. [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		14,400,000		17,600,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		83,500,000		59,600,000
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		41,700,000		19,300,000		37,700,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	3,000,000		8,300,000		13,200,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[3]	0		0		0
Settlements		(44,700,000)		(28,000,000)		(51,600,000)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		700,000
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	69,100,000		42,100,000		19,300,000
Ending Balance		69,100,000		41,700,000		19,300,000
Appalachian Power Co [Member] \| Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(1,000,000)		(5,800,000)
Appalachian Power Co [Member] \| Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		14,400,000		17,600,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		14,400,000		17,600,000
Appalachian Power Co [Member] \| Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		700,000		5,800,000
Appalachian Power Co [Member] \| Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Risk Management Assets
Derivative Assets				42,000,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		69,400,000		42,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities				300,000
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets	[7],[14]	69,100,000		42,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	3,500,000		800,000
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[7],[14]	(1,000,000)		(5,800,000)
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	(1,400,000)		(6,700,000)
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		0
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	700,000		5,800,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	4,600,000		7,200,000
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	69,400,000		42,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	300,000		300,000
Appalachian Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				0
Liabilities, Fair Value Disclosure
Derivative Liabilities				300,000
Appalachian Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]			32.20
Appalachian Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]			56.54
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	[10],[11]			44.77
Appalachian Power Co [Member] \| FTRs [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		69,400,000		42,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		300,000		0
Appalachian Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(2.82)		(0.30)
Appalachian Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	18.88		26.38
Appalachian Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	3.89		2.63
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		3,341,200,000		3,867,000,000
Total Assets		3,356,600,000		3,870,300,000
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		(700,000)		2,100,000		5,800,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	3,700,000		(100,000)		2,500,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[3]	0		0		0
Settlements		(3,000,000)		(2,200,000)		(8,600,000)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		400,000
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	4,600,000		(500,000)		2,000,000
Ending Balance		4,600,000		(700,000)		2,100,000
Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9,900,000		7,000,000
Total Assets		8,700,000		(1,100,000)
Indiana Michigan Power Co [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,142,600,000		2,619,600,000
Total Assets		2,142,600,000		2,619,600,000
Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,188,700,000		1,240,400,000
Total Assets		1,200,000,000		1,244,200,000
Indiana Michigan Power Co [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				7,600,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		5,300,000		7,600,000
Liabilities, Fair Value Disclosure
Derivative Liabilities				8,300,000
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets	[7],[14]	15,400,000		3,300,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		5,000,000
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[7],[14]	(1,200,000)		(8,100,000)
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	(1,300,000)		(10,000,000)
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		0
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	11,300,000		3,800,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	600,000		6,700,000
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	5,300,000		7,600,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	700,000		8,300,000
Indiana Michigan Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				0
Liabilities, Fair Value Disclosure
Derivative Liabilities				200,000
Indiana Michigan Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]			32.20
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	[10]			56.54
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	[10],[11]			44.77
Indiana Michigan Power Co [Member] \| FTRs [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		5,300,000		7,600,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		700,000		8,100,000
Indiana Michigan Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	0.16		(5.45)
Indiana Michigan Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	18.79		17.78
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	[10],[11]	1.23		(0.12)
Ohio Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		(92,500,000)		(110,300,000)		(103,600,000)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	6,500,000		2,400,000		(1,600,000)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[3]	0		0		0
Settlements		300,000		6,300,000		8,900,000
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	45,700,000		9,100,000		(14,000,000)
Ending Balance		(40,000,000)		(92,500,000)		(110,300,000)
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	39,700,000		92,500,000
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		(500,000)
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	(300,000)		0
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		0
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		500,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		0
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	40,000,000		92,500,000
Ohio Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities		40,000,000		92,500,000
Ohio Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	2.91		14.26
Ohio Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	187.34		52.98
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	[10],[11]	48.76		30.68
Public Service Co Of Oklahoma [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets	[7],[14]	25,300,000
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		12,100,000		10,300,000		15,800,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	24,200,000		16,100,000		11,900,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[3]	0		0		0
Settlements		(36,300,000)		(26,400,000)		(27,600,000)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	23,700,000		12,100,000		10,200,000
Ending Balance		23,700,000		12,100,000		10,300,000
Public Service Co Of Oklahoma [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets	[7],[14]	(300,000)
Public Service Co Of Oklahoma [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets	[7],[14]	0
Public Service Co Of Oklahoma [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets	[7],[14]	1,600,000
Public Service Co Of Oklahoma [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets	[7],[14]	24,000,000
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets		25,300,000		12,100,000	[7],[14]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	1,600,000		3,700,000
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets		1,300,000		(400,000)	[7],[14]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	(400,000)		(100,000)
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets		0		0	[7],[14]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		0
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets		0		300,000	[7],[14]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	1,700,000		3,700,000
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		24,000,000		12,200,000	[7],[14]
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	300,000		100,000
Public Service Co Of Oklahoma [Member] \| FTRs [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		24,000,000		12,200,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		300,000		100,000
Public Service Co Of Oklahoma [Member] \| FTRs [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(36.45)		(18.39)
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	[10]	3.40		1.87
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	[10],[11]	(7.55)		(2.57)
Public Service Co Of Oklahoma [Member] \| Interest Rate Foreign Currency Hedges [Member]
Risk Management Assets
Derivative Assets		0
Public Service Co Of Oklahoma [Member] \| Interest Rate Foreign Currency Hedges [Member] \| Other [Member]
Risk Management Assets
Derivative Assets		(1,600,000)
Public Service Co Of Oklahoma [Member] \| Interest Rate Foreign Currency Hedges [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets		0
Public Service Co Of Oklahoma [Member] \| Interest Rate Foreign Currency Hedges [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets		1,600,000
Public Service Co Of Oklahoma [Member] \| Interest Rate Foreign Currency Hedges [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		0
Southwestern Electric Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		10,900,000		1,600,000		1,400,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	35,800,000		9,500,000		2,800,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[3]	0		0		0
Settlements		(45,000,000)		(15,500,000)		(6,600,000)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	6,900,000		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	5,600,000		15,300,000		4,000,000
Ending Balance		14,200,000		10,900,000		$ 1,600,000
Southwestern Electric Power Co [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				11,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities				100,000
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member]
Risk Management Assets
Derivative Assets	[7],[14]	16,400,000		10,900,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	1,400,000		2,100,000
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Other [Member]
Risk Management Assets
Derivative Assets	[7],[14]	(400,000)		(400,000)
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	(600,000)		(100,000)
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	0		0
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	0		0
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	2,200,000		300,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	1,600,000		2,100,000
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets	[7],[14]	14,600,000		11,000,000
Liabilities, Fair Value Disclosure
Derivative Liabilities	[7],[14]	400,000		100,000
Southwestern Electric Power Co [Member] \| Natural Gas Contracts [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets				3,600,000
Liabilities, Fair Value Disclosure
Derivative Liabilities				0
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	[12]			3.11
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	[12]			4.02
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	[11],[12]			3.47
Southwestern Electric Power Co [Member] \| FTRs [Member] \| Level 3 [Member]
Risk Management Assets
Derivative Assets		14,600,000		7,400,000
Liabilities, Fair Value Disclosure
Derivative Liabilities		400,000		100,000
Southwestern Electric Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(36.45)		(18.39)
Southwestern Electric Power Co [Member] \| FTRs [Member] \| Level 3 [Member] \| High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	3.40		1.87
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	[10],[11]	(7.55)		(2.57)
Cash [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		47,100,000		48,000,000
Other Temporary Investments	[15]	47,100,000		48,000,000
Cash [Member] \| Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Cash [Member] \| Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		47,100,000		48,000,000
Cash [Member] \| Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Cash [Member] \| Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0		0
Other Cash Deposits [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	9,000,000		10,000,000
Other Cash Deposits [Member] \| Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	9,000,000		10,000,000
Other Cash Deposits [Member] \| Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Other Cash Deposits [Member] \| Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Other Cash Deposits [Member] \| Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[17]	144,100,000		154,800,000
Mutual Funds Fixed Income [Member] \| Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] \| Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		144,100,000		154,800,000
Mutual Funds Fixed Income [Member] \| Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] \| Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0		0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[18]	34,500,000		55,600,000
Mutual Funds Equity [Member] \| Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[18]	0		0
Mutual Funds Equity [Member] \| Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[18]	34,500,000		55,600,000
Mutual Funds Equity [Member] \| Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[18]	0		0
Mutual Funds Equity [Member] \| Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[18]	0		0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	21,200,000		84,700,000
Cash and Cash Equivalents [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	9,900,000		7,000,000
Cash and Cash Equivalents [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	11,300,000		77,700,000
Cash and Cash Equivalents [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0		0
Cash and Cash Equivalents [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0		0
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	21,200,000		84,700,000
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	9,900,000		7,000,000
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	11,300,000		77,700,000
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	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	[19]	0		0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,800,000		1,156,400,000
US Government Agencies Debt Securities [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,800,000		1,156,400,000
US Government Agencies Debt Securities [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,800,000		1,156,400,000
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,123,800,000		1,156,400,000
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		61,600,000		76,700,000
Corporate Debt Securities [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		61,600,000		76,700,000
Corporate Debt Securities [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] \| Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		61,600,000		76,700,000
Corporate Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate 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
Corporate Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		61,600,000		76,700,000
Corporate 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
State and Local Jurisdiction
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		3,300,000		7,300,000
State and Local Jurisdiction \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		3,300,000		7,300,000
State and Local Jurisdiction \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction \| Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		3,300,000		7,300,000
State and Local Jurisdiction \| Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction \| Indiana Michigan Power Co [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction \| Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		3,300,000		7,300,000
State and Local Jurisdiction \| Indiana Michigan Power Co [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,188,700,000		1,240,400,000
Fixed Income Funds [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,188,700,000		1,240,400,000
Fixed Income Funds [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,188,700,000		1,240,400,000
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,188,700,000		1,240,400,000
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	2,131,300,000		2,541,900,000
Domestic [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	2,131,300,000		2,541,900,000
Domestic [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] \| Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	2,131,300,000		2,541,900,000
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	2,131,300,000		2,541,900,000
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	$ 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]Included in cash flow hedges on the statements of comprehensive income.[4]Represents existing assets or liabilities that were previously categorized as Level 2.[5]Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.[6]Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.[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 December 31, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(7) million in 2023; Level 2 matures $182 million in 2023, $134 million in periods 2024-2026, $10 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $128 million in 2023, $6 million in periods 2024-2026, $6 million in periods 2027-2028 and $(5) million in periods 2029-2033. Risk management commodity contracts are substantially comprised of power contracts.[9]The December 31, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025; $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts.[10]Represents market prices in dollars per MWh.[11]The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.[12]Represents market prices in dollars per MMBtu.[13]See “Warrants Held in Investee” section of Note 10 in the 2021 Annual Report for additional information.[14]Substantially comprised of power contracts for the Registrant Subsidiaries.[15]Primarily represents amounts held for the repayment of debt.[16]Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.[17]Primarily short and intermediate maturities which may be sold and do not contain maturity dates.[18]Amounts represent publicly-traded equity securities and equity-based mutual funds.[19]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	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Federal:
Current	$ 113.1	$ (27.8)		$ (138.2)
Deferred	(88.8)	182.6		146.9
Total Federal	24.3	154.8		8.7
Current	26.6	6		(16.7)
Deferred	(45.5)	(45.3)		48.5
Total State and Local	(18.9)	(39.3)		31.8
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	5.4	115.5		40.5
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	2,305.6	2,488.1		2,196.7
Less: Equity Earnings	109.4	(91.7)		(91.1)
Income Tax Expense/Benefit	5.4	115.5		40.5
Pretax Income	2,309.6	2,600.2		2,234.3
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 485	$ 546		$ 469.2
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation	$ 17.1	$ 25.9		$ 26.5
Income Tax Reconciliation Nondeductible Expense Permanent Miscellaneous	11.5	(1.3)		(9.7)
Investment Tax Credit Amortization	(14.3)	(22)		(18.8)
Production Tax Credits	(197.1)	(98.8)		(83.1)
State and Local Income Taxes, Net	(14)	39.4		25.1
Removal Costs	(26.5)	(20)		(18.6)
AFUDC	(29.3)	(30.6)		(32.5)
Increase Decrease in Income Taxes Due to Tax Reserve Adjustments	0	(55.1)	[1]	0
Tax Reform Excess ADIT Reversal	(214.5)	(255.6)		(268.2)
Federal Return to Provision	(17.4)	(1.6)		(2.6)
CARES Act Provision	0	0		(48)
Other	4.9	(10.8)		1.2
Income Tax Expense/Benefit	$ 5.4	$ 115.5		$ 40.5
Effective Income Tax Rate	0.20%	4.40%		1.80%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 3,567.4	$ 3,347.1
Deferred Tax Liabilities	(12,464.3)	(11,991.2)
Property Related Temporary Differences	(7,788.1)	(7,346.4)
Amounts Due from Customers for Future Federal Income Taxes	962.7	1,086.6
Deferred State Income Taxes	(1,049.3)	(1,211.8)
Securitized Assets	(98.9)	(128.8)
Regulatory Assets	(865.2)	(746.6)
Accrued Nuclear Decommissioning	(632.7)	(743.2)
Net Operating Loss Carryforward	132.4	303.2
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Tax Credit Carryforward	612	440.1
Operating Lease Liability	142.9	116.3
Investment in Partnership	(338.9)	(392.1)
All Other, Net	44.8	41
Net Deferred Tax Liabilities	(8,896.9)	(8,644.1)
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,	14.3	13.2		$ 24.1
Increase - Tax Positions Taken During a Prior Period	5.1	1.2		0.6
Decrease - Tax Positions Taken During a Prior Period	0	(3.2)		(14.5)
Increase - Tax Positions Taken During the Current Year	3.8	3.1		3
Decrease - Settlements with Taxing Authorities	0	0		0
Decrease - Lapse of the Applicable Statute of Limitations	0	0		0
Balance at December 31,	23.2	14.3		13.2
Tax Contingency [Abstract]
Unrecognized Tax Benefits, if Recognized - Amount	23	14		12
Income Taxes (Textuals) [Abstract]
Valuation Allowance	(28.2)	(25)
Income Tax Expense/Benefit	5.4	115.5		40.5
Income Taxes Receivable		95
Income Tax Expense Re-Measurement		23
Operating Income (Loss)	(3,482.7)	(3,411.3)		(2,987.7)
Deferred Revenue	7.1	8.8
Liability, Retirement and Postemployment Benefits	2.5	(46.2)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	5.1	1.2		0.6
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	0	3.2		14.5
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	3.8	3.1		3
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	0	0		0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	0	0		0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0		0
Unrecognized Tax Benefits	$ 23.2	14.3		13.2
Income Tax Expense (Benefit), Continuing Operations, Adjustment of Deferred Tax (Asset) Liability				48
Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
AEP Texas Inc. [Member]
Federal:
Current	$ 29	(1.2)		5.2
Deferred	41.4	40.5		(15.4)
Total Federal	70.4	39.3		(10.2)
Current	2.2	3		(0.1)
Deferred	0	0.8		(0.9)
Total State and Local	2.2	3.8		(1)
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	72.6	43.1		(11.2)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	307.9	289.8		241
Income Tax Expense/Benefit	72.6	43.1		(11.2)
Pretax Income	380.5	332.9		229.8
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 79.9	$ 69.9		$ 48.3
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
State and Local Income Taxes, Net	$ 1.7	$ 2.4		$ (0.8)
AFUDC	(4.1)	(4.5)		(4.1)
Parent Company Loss Benefit	0	(3.2)		(4.5)
Tax Reform Excess ADIT Reversal	(5.5)	(21.3)		(47.9)
Other	0.6	(0.2)		(2.2)
Income Tax Expense/Benefit	$ 72.6	$ 43.1		$ (11.2)
Effective Income Tax Rate	19.10%	12.90%		(4.90%)
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 177	$ 173.8
Deferred Tax Liabilities	(1,321.2)	(1,262.7)
Property Related Temporary Differences	(1,130.7)	(1,060.2)
Amounts Due from Customers for Future Federal Income Taxes	111	110
Deferred State Income Taxes	(36.6)	(32.2)
Securitized Transition Assets	(65)	(84.4)
Regulatory Assets	(48.9)	(45.1)
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Operating Lease Liability	20.3	15.8
All Other, Net	5.7	7.2
Net Deferred Tax Liabilities	(1,144.2)	(1,088.9)
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	72.6	43.1		$ (11.2)
Operating Income (Loss)	$ (549.2)	(476)		(369.6)
AEP Texas Inc. [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
AEP Texas Inc. [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
AEP Transmission Co [Member]
Federal:
Current	$ 98	69.8		22.2
Deferred	46	54.1		65.4
Total Federal	144	123.9		87.6
Current	8.8	5.8		2.8
Deferred	16.3	14.4		16.3
Total State and Local	25.1	20.2		19.1
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	169.1	144.1		106.7
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	594.2	591.7		423.4
Income Tax Expense/Benefit	169.1	144.1		106.7
Pretax Income	763.3	735.8		530.1
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 160.3	$ 154.5		$ 111.3
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
State and Local Income Taxes, Net	$ 19.8	$ 19.8		$ 15.1
AFUDC	(14.8)	(14.1)		(15.5)
Parent Company Loss Benefit	0	(18.3)		(7)
Other	3.8	2.2		2.8
Income Tax Expense/Benefit	$ 169.1	$ 144.1		$ 106.7
Effective Income Tax Rate	22.20%	19.60%		20.10%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 165	$ 161.2
Deferred Tax Liabilities	(1,221.5)	(1,139.5)
Property Related Temporary Differences	(1,081.5)	(1,012.4)
Amounts Due from Customers for Future Federal Income Taxes	118.5	120.1
Deferred State Income Taxes	(108.1)	(97)
Regulatory Assets	(1.1)	(1.3)
Net Operating Loss Carryforward	5.5	8.1
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Tax Credit Carryforward	0.2	0.1
Operating Lease Liability	0.3	0.1
Investment in Partnership	(0.1)	(0.1)
All Other, Net	9.8	4.1
Net Deferred Tax Liabilities	(1,056.5)	(978.3)
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	169.1	144.1		$ 106.7
Operating Income (Loss)	$ (853.7)	(809.3)		(581.5)
AEP Transmission Co [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
AEP Transmission Co [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
Appalachian Power Co [Member]
Federal:
Current	$ (61)	5		21.4
Deferred	86.6	14.9		(27.1)
Total Federal	25.6	19.9		(5.7)
Current	(0.4)	2.2		9.3
Deferred	(7)	0		0.7
Total State and Local	(7.4)	2.2		10
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	18.2	22.1		4.3
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	394.2	348.9		369.7
Income Tax Expense/Benefit	18.2	22.1		4.3
Pretax Income	412.4	371		374
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 86.6	$ 77.9		$ 78.5
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation	$ 4.7	$ 11.7		$ 12.7
State and Local Income Taxes, Net	(5.9)	2.1		7.9
Removal Costs	(9.8)	(7.3)		(5.7)
AFUDC	(3.7)	(4.6)		(4.5)
Parent Company Loss Benefit	0	0		(6.2)
Increase Decrease in Income Taxes Due to Tax Reserve Adjustments	0	4.5	[1]	0
Tax Reform Excess ADIT Reversal	(50.9)	(60.5)		(72.3)
Federal Return to Provision	(2.8)	(1.6)		(7.2)
Other	0	(0.1)		1.1
Income Tax Expense/Benefit	$ 18.2	$ 22.1		$ 4.3
Effective Income Tax Rate	4.40%	6%		1.10%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 510.3	$ 495.1
Deferred Tax Liabilities	(2,502.5)	(2,299.8)
Property Related Temporary Differences	(1,509.8)	(1,476.5)
Amounts Due from Customers for Future Federal Income Taxes	163	182.1
Deferred State Income Taxes	(318.5)	(288.8)
Securitized Assets	(33.9)	(39.3)
Regulatory Assets	(301.2)	(177)
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Operating Lease Liability	15.6	14.2
All Other, Net	(7.4)	(19.4)
Net Deferred Tax Liabilities	(1,992.2)	(1,804.7)
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	18.2	22.1		$ 4.3
Operating Income (Loss)	$ (602.1)	(549.4)		(556.6)
Appalachian Power Co [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Appalachian Power Co [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
Indiana Michigan Power Co [Member]
Federal:
Current	$ 43.4	26.9		11.3
Deferred	(51.3)	(35.5)		(20.6)
Total Federal	(7.9)	(8.6)		(9.3)
Current	10.9	(0.6)		1.9
Deferred	1.2	(1.4)		(0.1)
Total State and Local	12.1	(2)		1.8
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	4.2	(10.6)		(7.5)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	324.7	279.8		284.8
Income Tax Expense/Benefit	4.2	(10.6)		(7.5)
Pretax Income	328.9	269.2		277.3
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 69.1	$ 56.5		$ 58.2
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation	$ 2.9	$ 3.5		$ 1.6
Investment Tax Credit Amortization	(3.1)	(6.4)		(4.5)
State and Local Income Taxes, Net	9.6	(1.3)		1.5
Removal Costs	(12.4)	(9.7)		(10.5)
AFUDC	(2.1)	(2.7)		(2.4)
Parent Company Loss Benefit	0	(2.8)		(6.4)
Tax Reform Excess ADIT Reversal	(54)	(46.3)		(46.8)
Federal Return to Provision	(6.2)	(0.6)		1.8
Other	0.4	(0.8)		0
Income Tax Expense/Benefit	$ 4.2	$ (10.6)		$ (7.5)
Effective Income Tax Rate	1.30%	(3.90%)		(2.70%)
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 933.7	$ 1,072.2
Deferred Tax Liabilities	(2,090.7)	(2,172.4)
Property Related Temporary Differences	(398)	(286.2)
Amounts Due from Customers for Future Federal Income Taxes	114.3	135.5
Deferred State Income Taxes	(227)	(222)
Regulatory Assets	(29.5)	(23.6)
Accrued Nuclear Decommissioning	(632.7)	(743.2)
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Operating Lease Liability	13.6	13.5
All Other, Net	2.3	25.8
Net Deferred Tax Liabilities	(1,157)	(1,100.2)
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	4.2	(10.6)		$ (7.5)
Operating Income (Loss)	$ (419.9)	(357.9)		(362.9)
Indiana Michigan Power Co [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Indiana Michigan Power Co [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
Ohio Power Co [Member]
Federal:
Current	$ (27)	6.8		(26.6)
Deferred	73.3	25.2		74
Total Federal	46.3	32		47.4
Current	(0.3)	(3.1)		(5.4)
Deferred	(1.8)	5.5		3.2
Total State and Local	(2.1)	2.4		(2.2)
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	44.2	34.4		45.2
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	287.8	253.6		271.4
Less: Equity Earnings	(0.6)	0		0
Income Tax Expense/Benefit	44.2	34.4		45.2
Pretax Income	331.4	288		316.6
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 69.6	$ 60.5		$ 66.5
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation	$ 3	$ 2.2		$ 3.7
State and Local Income Taxes, Net	(1.6)	0		(1.7)
AFUDC	(2.9)	(2.3)		(2.6)
Increase Decrease in Income Taxes Due to Tax Reserve Adjustments	0	8.9	[1]	0
Tax Reform Excess ADIT Reversal	(27.5)	(32.6)		(27.2)
Federal Return to Provision	3.5	(1.2)		6.5
Other	0.1	(1.1)		0
Income Tax Expense/Benefit	$ 44.2	$ 34.4		$ 45.2
Effective Income Tax Rate	13.30%	11.90%		14.30%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 218.8	$ 204.4
Deferred Tax Liabilities	(1,319.9)	(1,205.3)
Property Related Temporary Differences	(1,133.8)	(1,042)
Amounts Due from Customers for Future Federal Income Taxes	112.6	117.7
Deferred State Income Taxes	(59.6)	(58.8)
Regulatory Assets	(57.6)	(39.8)
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Operating Lease Liability	15.5	17.2
All Other, Net	21.8	4.8
Net Deferred Tax Liabilities	(1,101.1)	(1,000.9)
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,	0	3.2		$ 8.4
Increase - Tax Positions Taken During a Prior Period	5.1	0		0
Decrease - Tax Positions Taken During a Prior Period	0	(3.2)		(5.2)
Increase - Tax Positions Taken During the Current Year	0	0		0
Decrease - Settlements with Taxing Authorities	0	0		0
Decrease - Lapse of the Applicable Statute of Limitations	0	0		0
Balance at December 31,	5.1	0		3.2
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	44.2	34.4		45.2
Operating Income (Loss)	(413.7)	(385.2)		(403.7)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	5.1	0		0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	0	3.2		5.2
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	0	0		0
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	0	0		0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	0	0		0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0		0
Unrecognized Tax Benefits	$ 5.1	0		3.2
Ohio Power Co [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Ohio Power Co [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
Public Service Co Of Oklahoma [Member]
Federal:
Current	$ (3.3)	(109.6)		(11.4)
Deferred	(50.5)	105.6		8.3
Total Federal	(53.8)	(4)		(3.1)
Current	0	0		0.1
Deferred	4.6	8.1		8.2
Total State and Local	4.6	8.1		8.3
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	(49.2)	4.1		5.2
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	167.6	141.1		123
Income Tax Expense/Benefit	(49.2)	4.1		5.2
Pretax Income	118.4	145.2		128.2
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 24.9	$ 30.5		$ 26.9
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Investment Tax Credit Amortization	$ (1.6)	$ (1.8)		$ (2.1)
Production Tax Credits	(47.7)	(6)		0
State and Local Income Taxes, Net	4.3	6.4		6.5
Parent Company Loss Benefit	0	0		(0.2)
Tax Reform Excess ADIT Reversal	(25.4)	(25.4)		(25.5)
Federal Return to Provision	(3.7)	0.7		(0.5)
Other	0	(0.3)		0.1
Income Tax Expense/Benefit	$ (49.2)	$ 4.1		$ 5.2
Effective Income Tax Rate	(41.60%)	2.80%		4.10%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 225	$ 170
Deferred Tax Liabilities	(1,013.6)	(952.3)
Property Related Temporary Differences	(763.3)	(708.6)
Amounts Due from Customers for Future Federal Income Taxes	96	111.5
Deferred State Income Taxes	(81.9)	(83.2)
Regulatory Assets	(140.2)	(228)
Net Operating Loss Carryforward	25.8	111.4
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Tax Credit Carryforward	54.3	6.6
All Other, Net	20.7	8
Net Deferred Tax Liabilities	(788.6)	(782.3)
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	(49.2)	4.1		$ 5.2
Operating Income (Loss)	$ (180.8)	(192.9)		(175.9)
Public Service Co Of Oklahoma [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Public Service Co Of Oklahoma [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
Southwestern Electric Power Co [Member]
Federal:
Current	$ (32.3)	(16.7)		(13.6)
Deferred	13.4	26.2		19.6
Total Federal	(18.9)	9.5		6
Current	(1.8)	0.4		(8.2)
Deferred	(4.5)	(10.5)		11.6
Total State and Local	(6.3)	(10.1)		3.4
Income Tax Expense (Benefit):
Income Tax Expense/Benefit	(25.2)	(0.6)		9.4
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	294.3	242.1		183.7
Less: Equity Earnings	(1.4)	(3.4)		(2.9)
Income Tax Expense/Benefit	(25.2)	(0.6)		9.4
Pretax Income	267.7	238.1		190.2
Income Taxes on Pretax Income at Statutory Rate (21%)	$ 56.2	$ 50		$ 39.9
Federal Statutory Income Tax Rate	21%	21%		21%
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation	$ 2.3	$ 1.8		$ 1.9
Depletion	(4)	(2.7)		(3.4)
Production Tax Credits	(57.1)	(7.2)		0
State and Local Income Taxes, Net	(4.9)	(8)		2.7
Parent Company Loss Benefit	0	0		(5.6)
Tax Reform Excess ADIT Reversal	(14.8)	(31.1)		(21.9)
Other	(2.9)	(3.4)		(4.2)
Income Tax Expense/Benefit	$ (25.2)	$ (0.6)		$ 9.4
Effective Income Tax Rate	(9.40%)	(0.30%)		4.90%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	$ 374.9	$ 336.4
Deferred Tax Liabilities	(1,464.6)	(1,424)
Property Related Temporary Differences	(1,053.8)	(989.6)
Amounts Due from Customers for Future Federal Income Taxes	146.2	154.8
Deferred State Income Taxes	(208.7)	(234.9)
Regulatory Assets	(114.1)	(101.4)
Net Operating Loss Carryforward	42.7	67.4
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Tax Credit Carryforward	66	8.5
All Other, Net	32	7.6
Net Deferred Tax Liabilities	(1,089.7)	(1,087.6)
Income Taxes (Textuals) [Abstract]
Income Tax Expense/Benefit	(25.2)	(0.6)		$ 9.4
Operating Income (Loss)	$ (370)	(339.5)		(290.5)
Southwestern Electric Power Co [Member] \| Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Southwestern Electric Power Co [Member] \| Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2041
Arkansas
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 224.4
Arkansas \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2023
Arkansas \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2032
Arkansas \| Southwestern Electric Power Co [Member] \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2023
Arkansas \| Southwestern Electric Power Co [Member] \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2032
Kentucky
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 231.3
Kentucky \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Kentucky \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Louisiana
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 586.8
Louisiana \| Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	577.2
Oklahoma
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 943.3
Oklahoma \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Oklahoma \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Oklahoma \| AEP Transmission Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 33
Oklahoma \| AEP Transmission Co [Member] \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Oklahoma \| AEP Transmission Co [Member] \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Oklahoma \| Public Service Co Of Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 899.6
Oklahoma \| Public Service Co Of Oklahoma [Member] \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Oklahoma \| Public Service Co Of Oklahoma [Member] \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Tennessee
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 77.7
Tennessee \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Tennessee \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Virginia
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 11.2
Virginia \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Virginia \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
West Virginia
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 12.3
West Virginia \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029
West Virginia \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Ohio Municipal
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 1,257.7
Ohio Municipal \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2023
Ohio Municipal \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2027
Ohio Municipal \| Ohio Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 190.1
Ohio Municipal \| Ohio Power Co [Member] \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2024
Ohio Municipal \| Ohio Power Co [Member] \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2027
Colorado
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 82.6
Pennsylvania \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Pennsylvania \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2042
Illinois
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 52.4
Federal
Tax Credit Carryforward
Tax Credit Carryforward, Amount	612
Federal \| AEP Texas Inc. [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	1.5
Federal \| AEP Transmission Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0.2
Federal \| Appalachian Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	2
Federal \| Indiana Michigan Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	11.4
Federal \| Ohio Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	1
Federal \| Public Service Co Of Oklahoma [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	54.3
Federal \| Southwestern Electric Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	66
State and Local Jurisdiction
Tax Credit Carryforward
Tax Credit Carryforward, Amount	39.2
State and Local Jurisdiction \| AEP Texas Inc. [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0
State and Local Jurisdiction \| AEP Transmission Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0
State and Local Jurisdiction \| Appalachian Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0
State and Local Jurisdiction \| Indiana Michigan Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0
State and Local Jurisdiction \| Ohio Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0
State and Local Jurisdiction \| Public Service Co Of Oklahoma [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	39.2
State and Local Jurisdiction \| Southwestern Electric Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0
MICHIGAN
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 58.7
MICHIGAN \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029
MICHIGAN \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2031
NEW JERSEY
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 13.7
NEW JERSEY \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2036
NEW JERSEY \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2040
NEW MEXICO
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 22.9
PENNSYLVANIA
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 64.4
ILLINOIS \| Minimum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2031
ILLINOIS \| Maximum [Member]
Net Income Tax Operating Loss Carryforwards
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2041
Arkansas \| Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	$ 224.2
Dolet Hills Lignite Co, LLC [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Less: Equity Earnings	(1.4)	(3.4)		(2.9)
Dolet Hills Lignite Co, LLC [Member] \| Southwestern Electric Power Co [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Less: Equity Earnings	(1.4)	(3.4)		(2.9)
Investment funds \| Ohio Power Co [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Less: Equity Earnings	$ (0.6)	$ 0		$ 0

[1] 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements.

Leases (Details)

Leases (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
Leases (Details) - USD ($) $ in Millions		Feb. 23, 2023	Jan. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lease Rental Costs
Operating Lease, Cost				$ 157.5	$ 275.3	$ 279.6
Finance Lease Right-of-Use Asset Amortization				205.5	74.7	61.9
Interest Expense on Finance Leases				13.4	14.4	15.4
Total Lease Rental Costs	[1]			$ 376.4	$ 364.4	356.9
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				12 years 8 months 8 days	10 years 4 months 20 days
Weighted Average Remaining Lease Term, Finance Leases				4 years 7 months 9 days	2 years 11 months 12 days
Weighted Average Discount Rate, Operating Leases				3.54%	3.35%
Weighted Average Discount Rate, Finance Leases				5.76%	3.26%
Operating Cash Flows Used for Operating Leases				$ 155.1	$ 279.9
Operating Cash Flows Used for Finance Leases				13.6	14.3
Financing Cash Flows Used for Finance Leases				309.5	64	61.7
Non-cash Acquisitions Under Operating Leases				191.4	117
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				25,834.2	24,319.6
Other Property, Plant and Equipment				5,971.8	5,844.9
Total Property, Plant and Equipment				97,021.4	90,225
Accumulated Amortization				23,682.3	21,920.9
Net Property, Plant and Equipment Under Finance Leases				212.7	493
Other Liabilities, Noncurrent				607.3	603.8
Finance Lease Liability Due Within One Year				1,278.2	1,390.7
Total Obligations Under Finance Leases				225.7	503.5
Operating Lease Asset and Related Obligations
Operating Lease Assets				645.5	589
Operating Lease Noncurrent Liability				552.5	501.4
Operating Lease Liability Due Within One Year				113.6	99.8
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				666.1	601.2
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				67.9
Year 2				71.5
Year 3				41
Year 4				25
Year 5				19.3
Finance Leases, Later Years				32.6
Finance Leases, Total Future Minimum Lease Payments				257.3
Imputed Interest on Finance Leases				31.6
Total Obligations Under Finance Leases				225.7	503.5
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				138.7
Year 2				125.9
Year 3				86.7
Year 4				75.5
Year 5				65.6
Operating Leases, Later Years				352.2
Operating Leases, Total Future Minimum Lease Payments				844.6
Imputed Interest on Operating Leases				178.5
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				666.1	601.2
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				46
Leases (Textuals)
Repayments of Long-term Debt				2,345.4	2,989.3	1,339.8
Boat and Barge Leases [Member]
Leases (Textuals)
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases				27
Guarantor Obligations, Current Carrying Value				2
Guarantee Obligations Current Carrying Value Other Liabilities Current				1
Guarantee Obligations Current Carrying Value Other Liabilities Noncurrent				1
Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				120.9	389.9
Other Property, Plant and Equipment				321.4	328.1
Total Property, Plant and Equipment				442.3	718
Accumulated Amortization				229.6	225
Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				168.4	198.2
Finance Lease Liability Due Within One Year				57.3	305.3
Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				645.5	589
AEP Texas Inc. [Member]
Lease Rental Costs
Operating Lease, Cost				18.4	18.4	17.4
Finance Lease Right-of-Use Asset Amortization				6.8	6.7	6.3
Interest Expense on Finance Leases				1.3	1.4	1.5
Total Lease Rental Costs	[1]			$ 26.5	$ 26.5	25.2
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				4 years 3 months 29 days	5 years 10 months 28 days
Weighted Average Remaining Lease Term, Finance Leases				5 years 4 months 20 days	5 years 6 months 3 days
Weighted Average Discount Rate, Operating Leases				4.15%	3.53%
Weighted Average Discount Rate, Finance Leases				4.75%	4.31%
Operating Cash Flows Used for Operating Leases				$ 18.3	$ 18
Operating Cash Flows Used for Finance Leases				1.3	1.4
Financing Cash Flows Used for Finance Leases				6.8	6.7	6.3
Non-cash Acquisitions Under Operating Leases				36.7	4.4
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Property, Plant and Equipment				1,022.8	961.1
Total Property, Plant and Equipment				13,442.3	12,279.5
Accumulated Amortization				1,760.7	1,644.1
Net Property, Plant and Equipment Under Finance Leases				30.1	30.8
Other Liabilities, Noncurrent				93.2	73.8
Finance Lease Liability Due Within One Year				130.7	78
Total Obligations Under Finance Leases				30.1	30.8
Operating Lease Asset and Related Obligations
Operating Lease Noncurrent Liability				67.8	61.3
Operating Lease Liability Due Within One Year				28.6	14
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				96.4	75.3
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				8.3
Year 2				7.2
Year 3				5.5
Year 4				4.4
Year 5				3.5
Finance Leases, Later Years				5.5
Finance Leases, Total Future Minimum Lease Payments				34.4
Imputed Interest on Finance Leases				4.3
Total Obligations Under Finance Leases				30.1	30.8
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				32.3
Year 2				29.7
Year 3				13.1
Year 4				10.9
Year 5				8.3
Operating Leases, Later Years				11.7
Operating Leases, Total Future Minimum Lease Payments				106
Imputed Interest on Operating Leases				9.6
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				96.4	75.3
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				11.1
Leases (Textuals)
Repayments of Long-term Debt				716	88.7	392.1
AEP Texas Inc. [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				0	0
Other Property, Plant and Equipment				53.7	50.7
Total Property, Plant and Equipment				53.7	50.7
Accumulated Amortization				23.6	19.9
AEP Texas Inc. [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				23.1	24.2
Finance Lease Liability Due Within One Year				7	6.6
AEP Texas Inc. [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				94.7	73.6
AEP Transmission Co [Member]
Lease Rental Costs
Operating Lease, Cost				1.1	1.7	2.6
Finance Lease Right-of-Use Asset Amortization				0	0	0
Interest Expense on Finance Leases				0	0	0
Total Lease Rental Costs	[1]			$ 1.1	$ 1.7	2.6
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				2 years 18 days	2 years 11 months 12 days
Weighted Average Remaining Lease Term, Finance Leases				0 years	0 years
Weighted Average Discount Rate, Operating Leases				1.96%	0.90%
Weighted Average Discount Rate, Finance Leases				0%	0%
Operating Cash Flows Used for Operating Leases				$ 1	$ 1.6
Operating Cash Flows Used for Finance Leases				0	0
Financing Cash Flows Used for Finance Leases				0	0
Non-cash Acquisitions Under Operating Leases				1.7	2.1
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Property, Plant and Equipment				476.8	451.9
Total Property, Plant and Equipment				14,366.9	12,885.1
Accumulated Amortization				1,027	784.1
Net Property, Plant and Equipment Under Finance Leases				0	0
Other Liabilities, Noncurrent				69.1	3.2
Finance Lease Liability Due Within One Year				8.3	3.3
Total Obligations Under Finance Leases				0	0
Operating Lease Asset and Related Obligations
Operating Lease Noncurrent Liability				1.5	1.3
Operating Lease Liability Due Within One Year				1.3	0.9
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				2.8	2.2
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				0
Year 2				0
Year 3				0
Year 4				0
Year 5				0
Finance Leases, Later Years				0
Finance Leases, Total Future Minimum Lease Payments				0
Imputed Interest on Finance Leases				0
Total Obligations Under Finance Leases				0	0
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				1.4
Year 2				0.9
Year 3				0.4
Year 4				0.2
Year 5				0
Operating Leases, Later Years				0
Operating Leases, Total Future Minimum Lease Payments				2.9
Imputed Interest on Operating Leases				0.1
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				2.8	2.2
Leases (Textuals)
Repayments of Long-term Debt				104	50	0
AEP Transmission Co [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				0	0
Other Property, Plant and Equipment				0	0
Total Property, Plant and Equipment				0	0
Accumulated Amortization				0	0
AEP Transmission Co [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				0	0
Finance Lease Liability Due Within One Year				0	0
AEP Transmission Co [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				2.7	2
Appalachian Power Co [Member]
Lease Rental Costs
Operating Lease, Cost				17.9	19.3	19.1
Finance Lease Right-of-Use Asset Amortization				7.9	7.7	7.4
Interest Expense on Finance Leases				2	2.4	2.7
Total Lease Rental Costs	[1]			$ 27.8	$ 29.4	29.2
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				5 years 3 months 14 days	5 years 8 months 4 days
Weighted Average Remaining Lease Term, Finance Leases				4 years 3 months	4 years 11 months 19 days
Weighted Average Discount Rate, Operating Leases				3.61%	3.42%
Weighted Average Discount Rate, Finance Leases				7.09%	7.16%
Operating Cash Flows Used for Operating Leases				$ 17.9	$ 19.3
Operating Cash Flows Used for Finance Leases				2	2.4
Financing Cash Flows Used for Finance Leases				7.9	7.7	7.4
Non-cash Acquisitions Under Operating Leases				23.1	4.2
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				6,776.8	6,683.9
Other Property, Plant and Equipment				883.3	696.6
Total Property, Plant and Equipment				17,781.2	16,856.1
Accumulated Amortization				5,402	5,051.8
Net Property, Plant and Equipment Under Finance Leases				29.3	35.7
Other Liabilities, Noncurrent				49.6	34.6
Finance Lease Liability Due Within One Year				171.2	146.4
Total Obligations Under Finance Leases				29.3	35.7
Operating Lease Asset and Related Obligations
Operating Lease Assets				73.6	66.9
Operating Lease Noncurrent Liability				59.1	52.4
Operating Lease Liability Due Within One Year				15	15.1
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				74.1	67.5
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				9.6
Year 2				8.8
Year 3				7.5
Year 4				2.9
Year 5				1.8
Finance Leases, Later Years				2.8
Finance Leases, Total Future Minimum Lease Payments				33.4
Imputed Interest on Finance Leases				4.1
Total Obligations Under Finance Leases				29.3	35.7
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				17.5
Year 2				14.6
Year 3				11.8
Year 4				10.3
Year 5				9.1
Operating Leases, Later Years				19.2
Operating Leases, Total Future Minimum Lease Payments				82.5
Imputed Interest on Operating Leases				8.4
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				74.1	67.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				6.1
Leases (Textuals)
Repayments of Long-term Debt				230.4	393	140.3
Appalachian Power Co [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				41.1	42.8
Other Property, Plant and Equipment				20.1	20.4
Total Property, Plant and Equipment				61.2	63.2
Accumulated Amortization				31.9	27.5
Appalachian Power Co [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				21.6	28.1
Finance Lease Liability Due Within One Year				7.7	7.6
Appalachian Power Co [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				73.6	66.9
Indiana Michigan Power Co [Member]
Lease Rental Costs
Operating Lease, Cost				29.5	90.2	101.5
Finance Lease Right-of-Use Asset Amortization				78.7	12.9	6.5
Interest Expense on Finance Leases				3.1	3	3.1
Total Lease Rental Costs	[1]			$ 111.3	$ 106.1	111.1
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				5 years 9 months 14 days	5 years 10 months 13 days
Weighted Average Remaining Lease Term, Finance Leases				4 years 9 months 3 days	2 years 1 month 6 days
Weighted Average Discount Rate, Operating Leases				3.62%	3.46%
Weighted Average Discount Rate, Finance Leases				8.99%	3.02%
Operating Cash Flows Used for Operating Leases				$ 29.7	$ 92.9
Operating Cash Flows Used for Finance Leases				3.2	2.9
Financing Cash Flows Used for Finance Leases				130.7	6.8	6.5
Non-cash Acquisitions Under Operating Leases				19.1	2.6
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				5,585.1	5,531.8
Other Property, Plant and Equipment				839.3	792.9
Total Property, Plant and Equipment				11,544.3	11,210.7
Accumulated Amortization				4,132.8	3,899.8
Net Property, Plant and Equipment Under Finance Leases				33.8	160.7
Other Liabilities, Noncurrent				58.8	58.3
Finance Lease Liability Due Within One Year				98.9	123.2
Total Obligations Under Finance Leases				34	162.2
Operating Lease Asset and Related Obligations
Operating Lease Assets				64.3	63.5
Operating Lease Noncurrent Liability				48.9	48.9
Operating Lease Liability Due Within One Year				16	15.5
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				64.9	64.4
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				9.2
Year 2				12.1
Year 3				6.3
Year 4				3.9
Year 5				3.4
Finance Leases, Later Years				7.6
Finance Leases, Total Future Minimum Lease Payments				42.5
Imputed Interest on Finance Leases				8.5
Total Obligations Under Finance Leases				34	162.2
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				18.8
Year 2				17.7
Year 3				9.2
Year 4				8.3
Year 5				7.5
Operating Leases, Later Years				9.8
Operating Leases, Total Future Minimum Lease Payments				71.3
Imputed Interest on Operating Leases				6.4
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				64.9	64.4
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				4.4
Leases (Textuals)
Repayments of Long-term Debt				83.4	383.5	93.2
Indiana Michigan Power Co [Member] \| Notes Payable, Other Payables [Member] \| Subsequent Event [Member]
Leases (Textuals)
Repayments of Long-term Debt		$ 8	$ 8
Indiana Michigan Power Co [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				28	156.8
Other Property, Plant and Equipment				40.6	42.1
Total Property, Plant and Equipment				68.6	198.9
Accumulated Amortization				34.8	38.2
Indiana Michigan Power Co [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				27.1	31.7
Finance Lease Liability Due Within One Year				6.9	130.5
Indiana Michigan Power Co [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				64.3	63.5
Ohio Power Co [Member]
Lease Rental Costs
Operating Lease, Cost				16.9	19	17.1
Finance Lease Right-of-Use Asset Amortization				4.9	4.9	4.7
Interest Expense on Finance Leases				0.8	0.8	0.9
Total Lease Rental Costs	[1]			$ 22.6	$ 24.7	22.7
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				5 years 11 months 23 days	6 years 8 months 8 days
Weighted Average Remaining Lease Term, Finance Leases				5 years 3 months 7 days	5 years 6 months 14 days
Weighted Average Discount Rate, Operating Leases				3.73%	3.56%
Weighted Average Discount Rate, Finance Leases				4.53%	4.19%
Operating Cash Flows Used for Operating Leases				$ 17.5	$ 19
Operating Cash Flows Used for Finance Leases				0.8	0.8
Financing Cash Flows Used for Finance Leases				4.9	4.9	4.7
Non-cash Acquisitions Under Operating Leases				8.4	4.2
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Property, Plant and Equipment				1,051.4	992.9
Total Property, Plant and Equipment				11,174.6	10,421.3
Accumulated Amortization				2,565.3	2,458.3
Net Property, Plant and Equipment Under Finance Leases				18.9	19.3
Other Liabilities, Noncurrent				66	29.2
Finance Lease Liability Due Within One Year				154.2	118.1
Total Obligations Under Finance Leases				18.9	19.3
Operating Lease Asset and Related Obligations
Operating Lease Assets				73.8	81.2
Operating Lease Noncurrent Liability				60.3	68.6
Operating Lease Liability Due Within One Year				13.5	13.1
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				73.8	81.7
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				5.4
Year 2				4.6
Year 3				3.2
Year 4				2.6
Year 5				2.1
Finance Leases, Later Years				3.4
Finance Leases, Total Future Minimum Lease Payments				21.3
Imputed Interest on Finance Leases				2.4
Total Obligations Under Finance Leases				18.9	19.3
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				16.4
Year 2				14.9
Year 3				13.2
Year 4				12
Year 5				10.7
Operating Leases, Later Years				15.7
Operating Leases, Total Future Minimum Lease Payments				82.9
Imputed Interest on Operating Leases				9.1
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				73.8	81.7
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				7.6
Leases (Textuals)
Repayments of Long-term Debt				0.1	500.1	0.1
Ohio Power Co [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				0	0
Other Property, Plant and Equipment				32.7	32.1
Total Property, Plant and Equipment				32.7	32.1
Accumulated Amortization				13.8	12.8
Ohio Power Co [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				14.2	14.9
Finance Lease Liability Due Within One Year				4.7	4.4
Ohio Power Co [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				73.8	81.2
Public Service Co Of Oklahoma [Member]
Lease Rental Costs
Operating Lease, Cost				11.8	8.7	7.8
Finance Lease Right-of-Use Asset Amortization				3.2	3.2	3.5
Interest Expense on Finance Leases				0.6	0.6	0.7
Total Lease Rental Costs	[1]			$ 15.6	$ 12.5	12
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				23 years 10 months 24 days	20 years 10 months 20 days
Weighted Average Remaining Lease Term, Finance Leases				6 years 7 days	6 years 2 months 4 days
Weighted Average Discount Rate, Operating Leases				3.43%	3.35%
Weighted Average Discount Rate, Finance Leases				4.63%	4.23%
Operating Cash Flows Used for Operating Leases				$ 10.5	$ 8.7
Operating Cash Flows Used for Finance Leases				0.6	0.6
Financing Cash Flows Used for Finance Leases				3.2	3.2	3.5
Non-cash Acquisitions Under Operating Leases				46	33.4
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				2,394.8	1,802.4
Other Property, Plant and Equipment				469.3	437
Total Property, Plant and Equipment				7,464.2	6,508
Accumulated Amortization				1,837.7	1,705.2
Net Property, Plant and Equipment Under Finance Leases				15	15.3
Other Liabilities, Noncurrent				21.3	19.4
Finance Lease Liability Due Within One Year				101.8	66.4
Total Obligations Under Finance Leases				15	15.3
Operating Lease Asset and Related Obligations
Operating Lease Assets				106.1	68.9
Operating Lease Noncurrent Liability				99.3	62.2
Operating Lease Liability Due Within One Year				8.9	6.9
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				108.2	69.1
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				3.8
Year 2				3.3
Year 3				2.5
Year 4				2.2
Year 5				1.8
Finance Leases, Later Years				3.7
Finance Leases, Total Future Minimum Lease Payments				17.3
Imputed Interest on Finance Leases				2.3
Total Obligations Under Finance Leases				15	15.3
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				11.5
Year 2				10.7
Year 3				9.5
Year 4				8.6
Year 5				7.8
Operating Leases, Later Years				116.4
Operating Leases, Total Future Minimum Lease Payments				164.5
Imputed Interest on Operating Leases				56.3
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				108.2	69.1
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				4.8
Leases (Textuals)
Repayments of Long-term Debt				500.5	750.5	13.2
Public Service Co Of Oklahoma [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				0.6	0.6
Other Property, Plant and Equipment				25.2	23.9
Total Property, Plant and Equipment				25.8	24.5
Accumulated Amortization				10.8	9.2
Public Service Co Of Oklahoma [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				11.7	12.3
Finance Lease Liability Due Within One Year				3.3	3
Public Service Co Of Oklahoma [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				106.1	68.9
Southwestern Electric Power Co [Member]
Lease Rental Costs
Operating Lease, Cost				15.3	12.1	9.4
Finance Lease Right-of-Use Asset Amortization				10.8	11	10.9
Interest Expense on Finance Leases				2.1	2.5	2.2
Total Lease Rental Costs	[1]			$ 28.2	$ 25.6	22.5
Supplemental Information Related to Leases
Weighted-Average Remaining Lease Term, Operating Leases				23 years 6 months 18 days	20 years 2 months 26 days
Weighted Average Remaining Lease Term, Finance Leases				4 years 1 month 17 days	4 years 6 months 10 days
Weighted Average Discount Rate, Operating Leases				3.41%	3.34%
Weighted Average Discount Rate, Finance Leases				4.80%	4.68%
Operating Cash Flows Used for Operating Leases				$ 13.7	$ 11.6
Operating Cash Flows Used for Finance Leases				2.1	2.5
Financing Cash Flows Used for Finance Leases				10.8	10.9	10.9
Non-cash Acquisitions Under Operating Leases				53.6	42.9
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				5,476.2	4,734.5
Other Property, Plant and Equipment				804.4	764
Total Property, Plant and Equipment				11,789.5	10,570.4
Accumulated Amortization				3,527.3	3,170.3
Net Property, Plant and Equipment Under Finance Leases				29.6	42.2
Other Liabilities, Noncurrent				68.4	63
Finance Lease Liability Due Within One Year				172	154.6
Total Obligations Under Finance Leases				42.2	49.7
Operating Lease Asset and Related Obligations
Operating Lease Noncurrent Liability				120.2	77.7
Operating Lease Liability Due Within One Year				8.4	8.1
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				128.6	85.8
Finance Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				12.4
Year 2				16.5
Year 3				6.1
Year 4				2.8
Year 5				2.4
Finance Leases, Later Years				5.6
Finance Leases, Total Future Minimum Lease Payments				45.8
Imputed Interest on Finance Leases				3.6
Total Obligations Under Finance Leases				42.2	49.7
Operating Lease Liabilities Rolling Future Minimum Lease Payments
Year 1				14.4
Year 2				12.7
Year 3				11.4
Year 4				10.2
Year 5				8.8
Operating Leases, Later Years				141.8
Operating Leases, Total Future Minimum Lease Payments				199.3
Imputed Interest on Operating Leases				70.7
Estimated Present Value of Future Minimum Lease Payments on Operating Leases				128.6	85.8
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements				5.3
Leases (Textuals)
Repayments of Long-term Debt				6.2	381.2	$ 21.2
Southwestern Electric Power Co [Member] \| Finance Lease Assets [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Generation				25.9	34.3
Other Property, Plant and Equipment				58.3	55.7
Total Property, Plant and Equipment				84.2	90
Accumulated Amortization				54.6	47.8
Southwestern Electric Power Co [Member] \| Finance Lease Liabilities [Member]
Property, Plant and Equipment and Other Related Obligations Under Finance Leases
Other Liabilities, Noncurrent				31.3	38.9
Finance Lease Liability Due Within One Year				10.9	10.8
Southwestern Electric Power Co [Member] \| Operating Lease Assets [Member]
Operating Lease Asset and Related Obligations
Operating Lease Assets				$ 123.4	$ 80.1

[1]Excludes variable and short-term lease costs, which were immaterial.

Financing Activities (Details)

Financing Activities (Details) - USD ($)		1 Months Ended			12 Months Ended
Financing Activities (Details) - USD ($)		Feb. 23, 2023	Jan. 31, 2023	Jan. 31, 2022	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Shares of Company
Beginning Balance, Shares			525,099,321	524,416,175	524,416,175	516,808,354		514,373,631
Issued					683,146	7,607,821		2,434,723
Ending Balance, Shares					525,099,321	524,416,175		516,808,354
Treasury Stock, Shares, Beginning Balance			11,233,240	20,204,160	20,204,160	20,204,160		20,204,160
Partners' Capital Account, Units, Treasury Units Reissued	[1]				8,970,920
Treasury Stock, Shares, Ending Balance					11,233,240	20,204,160		20,204,160
Long-term Debt
Senior Unsecured Notes					$ 30,174,800,000	$ 28,185,700,000
Pollution Control Bonds	[2]				1,770,200,000	1,869,300,000
Notes Payable	[3]				269,700,000	211,300,000
Securitization Bonds					487,800,000	603,500,000
Spent Nuclear Fuel Obligation	[4]				285,600,000	281,300,000
Junior Subordinated Notes	[5]				2,381,300,000	2,373,000,000
Other Long-term Debt					1,431,600,000	1,033,500,000
Total Long-term Debt Outstanding					36,801,000,000	34,557,600,000
Outstanding Long-term Debt
Principal Amount, 2023					2,486,400,000
Principal Amount, 2024	[6]				1,590,200,000
Principal Amount, 2025	[7]				3,253,900,000
Principal Amount, 2026					1,754,000,000
Principal Amount, 2027					2,251,900,000
Principal Amount, After 2027					25,773,800,000
Principal Amount, Total					37,110,200,000
Unamortized Discount, Net and Debt Issuance Costs					(309,200,000)
Total Long-term Debt Outstanding					36,801,000,000	34,557,600,000
Short-term Debt
Securitized Debt for Receivables	[8]				750,000,000	750,000,000
Commercial Paper					2,862,200,000	1,364,000,000
Total Short-term Debt					$ 4,112,200,000	$ 2,614,000,000
Securitized Debt for Receivables	[8],[9]				4.67%	0.19%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable					1.84%	0.19%		0.85%
Net Uncollectible Accounts Receivable Written Off					$ 29,500,000	$ 26,500,000		$ 15,300,000
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts					1,167,700,000
Total Principal Outstanding					750,000,000	750,000,000
Delinquent Securitized Accounts Receivable					44,200,000	57,900,000
Bad Debt Reserves Related to Securitized Sale of Accounts Receivable					39,700,000	42,800,000
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable					360,900,000	307,100,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					19,639,500,000	16,792,000,000		14,918,500,000
Financing Activities (Textuals)
Repayments of Long-term Debt					2,345,400,000	2,989,300,000		1,339,800,000
Proceeds from Issuance of Long-term Debt					4,649,700,000	6,486,300,000		5,626,100,000
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,					$ 56,400,000	47,800,000		(86,200,000)
Maximum Percentage Debt to Capitalization					67.50%
Restricted Net Assets					$ 16,200,000,000
Dividend Restrictions	[10]				3,023,000,000
Retained Earnings Available to Pay Dividends					8,100,000,000
Dividends Paid on Common Stock					(1,645,200,000)	(1,519,500,000)		(1,424,900,000)
Credit Facilities, Total					5,000,000,000
Maximum Value of Shares to be Issued Under ATM Program					$ 1,000,000,000
Maximum Percentage Paid to Selling Agents					2%
Issuance of Common Stock, Net					$ 826,500,000	600,500,000		155,000,000
Commitment From Bank Conduits to Finance Receivables (One) [Domain]					125,000,000
Commitment from Bank Conduits to Finance Receivables Two					625,000,000
Total Commitment From Bank Conduits To Finance Receivables					$ 750,000,000
2019 Equity Units [Member]
Shares of Company
Issued					8,970,920
Financing Activities (Textuals)
Equity Units Issued					16,100,000
Per Unit Conversion for Equity Units					$ 50
Net Equity Units Issuance Proceeds					785,000,000
Principal Amounts of Junior Subordinated Debt					$ 1,000
Forward Equity Purchase Contract Date					2022
Corporate unit ownership share of an equity unit					5%
Issuance of Common Stock, Net					$ 805,000,000
2020 Equity Units [Member]
Financing Activities (Textuals)
Equity Units Issued					17,000,000
Per Unit Conversion for Equity Units					$ 50
Net Equity Units Issuance Proceeds					833,000,000
Principal Amounts of Junior Subordinated Debt					$ 1,000
Forward Equity Purchase Contract Date					2023
Equity Units Annual Distribution Rate					6.125%
Forward Equity Contract Payment Rate					4.825%
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,					$ 0	$ 0		110,600,000
Maximum Shares Issued Under Equity Units Conversion					10,205,100
Corporate unit ownership share of an equity unit					5%
Minimum [Member] \| 2020 Equity Units [Member]
Financing Activities (Textuals)
AEP Share Price for Equity Unit Conversion					$ 83.29
Shares Per Equity Unit					0.5003
Maximum [Member] \| 2020 Equity Units [Member]
Financing Activities (Textuals)
AEP Share Price for Equity Unit Conversion					$ 99.95
Shares Per Equity Unit					0.6003
Commercial Paper [Member]
Short-term Debt
Debt, Weighted Average Interest Rate	[9]				4.80%	0.34%
Financing Activities (Textuals)
Weighted Average Interest Rate of Commercial Paper Outstanding During Year					2.74%
Maximum Amount of Commercial Paper Outstanding					$ 2,900,000,000
364 Day Term Loan
Short-term Debt
Debt, Weighted Average Interest Rate	[9]				0%	0.81%
Other Short-term Borrowings					$ 0	$ 500,000,000
Term Loan 1
Short-term Debt
Debt, Weighted Average Interest Rate	[9]				5.17%	0%
Other Short-term Borrowings					$ 125,000,000	$ 0
Term Loan 2
Short-term Debt
Debt, Weighted Average Interest Rate	[9]				5.17%	0%
Other Short-term Borrowings					$ 150,000,000	$ 0
Term Loan 3
Short-term Debt
Debt, Weighted Average Interest Rate	[9]				5.23%	0%
Other Short-term Borrowings					$ 100,000,000	$ 0
Term Loan 4
Short-term Debt
Debt, Weighted Average Interest Rate	[9]				4.87%	0%
Other Short-term Borrowings					$ 125,000,000	$ 0
Securitized Debt
Short-term Debt
Securitized Debt for Receivables					$ 750,000,000
Financing Activities (Textuals)
Weighted Average Interest Rate of Commercial Paper Outstanding During Year					1.84%
AEP Texas Inc. [Member]
Long-term Debt
Senior Unsecured Notes					$ 4,702,700,000	4,135,500,000
Pollution Control Bonds					440,200,000	439,900,000
Securitization Bonds					314,400,000	404,700,000
Other Long-term Debt					200,500,000	200,700,000
Total Long-term Debt Outstanding					5,657,800,000	5,180,800,000
Outstanding Long-term Debt
Principal Amount, 2023					278,500,000
Principal Amount, 2024					96,000,000
Principal Amount, 2025					524,500,000
Principal Amount, 2026					75,000,000
Principal Amount, 2027					25,600,000
Principal Amount, After 2027					4,706,400,000
Principal Amount, Total					5,706,000,000
Unamortized Discount, Net and Debt Issuance Costs					(48,200,000)
Total Long-term Debt Outstanding					5,657,800,000	5,180,800,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					1,848,000,000	1,587,700,000		1,528,000,000
Financing Activities (Textuals)
Repayments of Long-term Debt					716,000,000	88,700,000		392,100,000
Proceeds from Issuance of Long-term Debt					$ 1,188,600,000	444,200,000		$ 652,700,000
Maximum Percentage Debt to Capitalization					67.50%
Dividend Restrictions					$ 1,105,700,000
AEP Texas Inc. [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					348,800,000	355,500,000
Maximum Loans to Money Pool					652,300,000	104,700,000
Average Borrowings from Money Pool					173,300,000	172,500,000
Average Loans to Money Pool					247,800,000	40,000,000
Net Loans (Borrowings) to/from Money Pool					(96,500,000)	(26,900,000)
Authorized Short Term Borrowing Limit					$ 500,000,000	$ 500,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					1.08%	0.33%		1.51%
Average Interest Rate For Funds Loaned					1.99%	0.26%		0.81%
AEP Texas Inc. [Member] \| Utility [Member] \| Nonutility [Member]
Financing Activities (Textuals)
Interest Expense, Related Party					$ 900,000	$ 300,000		$ 800,000
Interest Income Earned on Advances to the Money Pool					$ 2,600,000	$ 100,000		$ 700,000
AEP Texas Inc. [Member] \| Nonutility [Member]
Maximum Interest Rate For Funds Loaned					5.28%	0.58%		2.70%
Minimum Interest Rate for Funds Loaned					0.46%	0.21%		0.27%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Loans to Money Pool					$ 7,000,000	$ 7,100,000
Average Loans to Money Pool					6,800,000	6,900,000
Net Loans (Borrowings) to/from Money Pool					$ 6,900,000	$ 6,900,000
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Loaned					2.23%	0.37%		1.18%
AEP Transmission Co [Member]
Long-term Debt
Senior Unsecured Notes					$ 4,782,800,000	$ 4,343,900,000
Total Long-term Debt Outstanding					4,782,800,000	4,343,900,000
Outstanding Long-term Debt
Principal Amount, 2023					60,000,000
Principal Amount, 2024					95,000,000
Principal Amount, 2025					90,000,000
Principal Amount, 2026					425,000,000
Principal Amount, 2027					0
Principal Amount, After 2027					4,166,000,000
Principal Amount, Total					4,836,000,000
Unamortized Discount, Net and Debt Issuance Costs					(53,200,000)
Total Long-term Debt Outstanding					4,782,800,000	4,343,900,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					1,651,700,000	1,410,900,000		$ 1,232,700,000
Financing Activities (Textuals)
Repayments of Long-term Debt					104,000,000	50,000,000		0
Proceeds from Issuance of Long-term Debt					540,800,000	443,700,000		$ 519,500,000
Sub-Limit of Secured Debt					$ 50,000,000
Maximum Percentage of Consolidated Tangible Net Assets					10%
Tangible Capital to Tangible Assets					0.019
Maximum Percentage Debt to Capitalization					67.50%
Dividend Restrictions					$ 0
AEP Transmission Co [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					480,200,000	444,900,000
Maximum Loans to Money Pool					137,000,000	117,300,000
Average Borrowings from Money Pool					189,400,000	189,100,000
Average Loans to Money Pool					28,900,000	29,700,000
Net Loans (Borrowings) to/from Money Pool					(195,500,000)	(108,800,000)
Authorized Short Term Borrowing Limit	[11]				$ 820,000,000	$ 820,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					1.81%	0.32%		1.29%
Average Interest Rate For Funds Loaned					2.47%	0.10%		1.99%
AEP Transmission Co [Member] \| Utility [Member] \| Direct Borrowing [Member]
Financing Activities (Textuals)
Interest Expense, Related Party					$ 3,500,000	$ 600,000		$ 1,500,000
Interest Income Earned on Advances to the Money Pool					$ 1,600,000	$ 400,000		$ 2,400,000
AEP Transmission Co [Member] \| Direct Borrowing [Member]
Maximum Interest Rate for Funds Borrowed					5.28%	0.86%		2.70%
Minimum Interest Rate For Funds Borrowed					0.46%	0.25%		0.27%
Maximum Interest Rate For Funds Loaned					5.28%	0.86%		2.70%
Minimum Interest Rate for Funds Loaned					0.46%	0.25%		0.27%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					$ 52,400,000	$ 14,600,000
Maximum Loans to Money Pool					141,800,000	224,200,000
Average Borrowings from Money Pool					6,700,000	1,800,000
Average Loans to Money Pool					57,500,000	118,000,000
Borrowings from Parent					29,400,000	1,500,000
Loans to Parent					0	12,700,000
Authorized Short Term Borrowing Limit	[12]				$ 50,000,000	$ 50,000,000
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.08%	0.38%		1.20%
Average Interest Rate For Funds Loaned					2.07%	0.35%		1.13%
Appalachian Power Co [Member]
Long-term Debt
Senior Unsecured Notes					$ 4,581,400,000	$ 4,083,700,000
Pollution Control Bonds	[2]				429,400,000	529,500,000
Securitization Bonds					173,300,000	198,800,000
Other Long-term Debt					226,400,000	126,900,000
Total Long-term Debt Outstanding					5,410,500,000	4,938,900,000
Outstanding Long-term Debt
Principal Amount, 2023					251,800,000
Principal Amount, 2024					113,500,000
Principal Amount, 2025					673,300,000
Principal Amount, 2026					30,900,000
Principal Amount, 2027					355,600,000
Principal Amount, After 2027					4,031,800,000
Principal Amount, Total					5,456,900,000
Unamortized Discount, Net and Debt Issuance Costs					(46,400,000)
Total Long-term Debt Outstanding					5,410,500,000	4,938,900,000
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues					194,400,000	153,100,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					3,520,700,000	3,092,900,000		$ 2,809,200,000
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit					1,552,900,000	1,324,100,000		1,272,900,000
Financing Activities (Textuals)
Repayments of Long-term Debt					230,400,000	393,000,000		140,300,000
Proceeds from Issuance of Long-term Debt					$ 698,000,000	494,000,000		$ 606,900,000
Maximum Percentage Debt to Capitalization					67.50%
Dividend Restrictions					$ 543,100,000
Appalachian Power Co [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					438,400,000	199,300,000
Maximum Loans to Money Pool					214,200,000	616,900,000
Average Borrowings from Money Pool					181,700,000	87,500,000
Average Loans to Money Pool					45,400,000	118,300,000
Net Loans (Borrowings) to/from Money Pool					(162,400,000)	(178,500,000)
Authorized Short Term Borrowing Limit					$ 500,000,000	$ 500,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.34%	0.41%		2.12%
Average Interest Rate For Funds Loaned					2.39%	0.25%		0.85%
Financing Activities (Textuals)
Interest Expense, Related Party					$ 5,600,000	$ 100,000		$ 2,800,000
Interest Income Earned on Advances to the Money Pool					2,800,000	300,000		700,000
Indiana Michigan Power Co [Member]
Long-term Debt
Senior Unsecured Notes					2,597,300,000	2,595,500,000
Pollution Control Bonds	[2]				189,000,000	188,700,000
Notes Payable	[3]				183,800,000	122,200,000
Spent Nuclear Fuel Obligation	[4]				285,600,000	281,300,000
Other Long-term Debt					5,100,000	7,300,000
Total Long-term Debt Outstanding					3,260,800,000	3,195,000,000
Outstanding Long-term Debt
Principal Amount, 2023					341,800,000
Principal Amount, 2024					56,400,000
Principal Amount, 2025					220,500,000
Principal Amount, 2026					8,500,000
Principal Amount, 2027					1,700,000
Principal Amount, After 2027					2,660,600,000
Principal Amount, Total					3,289,500,000
Unamortized Discount, Net and Debt Issuance Costs					(28,700,000)
Total Long-term Debt Outstanding					3,260,800,000	3,195,000,000
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues					166,900,000	156,900,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					2,659,700,000	2,330,700,000		2,236,000,000
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit					2,045,600,000	1,927,000,000		1,891,800,000
Financing Activities (Textuals)
Repayments of Long-term Debt					83,400,000	383,500,000		93,200,000
Proceeds from Issuance of Long-term Debt					$ 142,700,000	546,700,000		$ 69,500,000
Maximum Percentage Debt to Capitalization					67.50%
Dividend Restrictions					$ 688,200,000
Indiana Michigan Power Co [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					318,600,000	166,500,000
Maximum Loans to Money Pool					23,000,000	368,200,000
Average Borrowings from Money Pool					105,200,000	110,400,000
Average Loans to Money Pool					22,300,000	67,700,000
Net Loans (Borrowings) to/from Money Pool					(226,900,000)	(71,800,000)
Authorized Short Term Borrowing Limit					$ 500,000,000	$ 500,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.57%	0.33%		1.07%
Average Interest Rate For Funds Loaned					2.20%	0.23%		1.18%
Financing Activities (Textuals)
Interest Expense, Related Party					$ 2,900,000	$ 200,000		$ 1,400,000
Interest Income Earned on Advances to the Money Pool					500,000	200,000		200,000
Ohio Power Co [Member]
Long-term Debt
Senior Unsecured Notes					2,969,700,000	2,967,800,000
Other Long-term Debt					600,000	700,000
Total Long-term Debt Outstanding					2,970,300,000	2,968,500,000
Outstanding Long-term Debt
Principal Amount, 2023					100,000
Principal Amount, 2024					100,000
Principal Amount, 2025					100,000
Principal Amount, 2026					100,000
Principal Amount, 2027					100,000
Principal Amount, After 2027					3,000,100,000
Principal Amount, Total					3,000,600,000
Unamortized Discount, Net and Debt Issuance Costs					(30,300,000)
Total Long-term Debt Outstanding					2,970,300,000	2,968,500,000
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues					478,600,000	392,700,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					3,672,100,000	2,837,500,000		2,665,000,000
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit					3,101,300,000	2,458,500,000		2,366,200,000
Financing Activities (Textuals)
Repayments of Long-term Debt					100,000	500,100,000		100,000
Proceeds from Issuance of Long-term Debt					0	1,037,100,000		$ 347,000,000
Dividend Restrictions					0
Ohio Power Co [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					262,500,000	259,200,000
Maximum Loans to Money Pool					246,100,000	622,900,000
Average Borrowings from Money Pool					101,300,000	61,600,000
Average Loans to Money Pool					86,900,000	127,200,000
Net Loans (Borrowings) to/from Money Pool					(172,900,000)	42,000,000
Authorized Short Term Borrowing Limit					$ 500,000,000	$ 500,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					3.51%	0.27%		0.99%
Average Interest Rate For Funds Loaned					1.22%	0.14%		2.06%
Financing Activities (Textuals)
Interest Expense, Related Party					$ 2,300,000	$ 100,000		$ 1,800,000
Interest Income Earned on Advances to the Money Pool					$ 400,000	$ 100,000		0
Public Service Co Of Oklahoma [Member]
Shares of Company
Beginning Balance, Shares			10,482,000	10,482,000	10,482,000
Ending Balance, Shares					10,482,000	10,482,000
Long-term Debt
Senior Unsecured Notes					$ 1,785,600,000	$ 1,785,500,000
Other Long-term Debt					127,200,000	128,000,000
Total Long-term Debt Outstanding					1,912,800,000	1,913,500,000
Outstanding Long-term Debt
Principal Amount, 2023					500,000
Principal Amount, 2024					600,000
Principal Amount, 2025					250,600,000
Principal Amount, 2026					50,600,000
Principal Amount, 2027					300,000
Principal Amount, After 2027					1,625,000,000
Principal Amount, Total					1,927,600,000
Unamortized Discount, Net and Debt Issuance Costs					(14,800,000)
Total Long-term Debt Outstanding					1,912,800,000	1,913,500,000
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues					155,500,000	114,500,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					1,875,700,000	1,474,300,000		1,263,900,000
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit					1,809,500,000	1,406,400,000		1,221,000,000
Financing Activities (Textuals)
Repayments of Long-term Debt					500,500,000	750,500,000		13,200,000
Proceeds from Issuance of Long-term Debt					$ 499,700,000	1,290,000,000		$ 0
Maximum Percentage Debt to Capitalization					67.50%
Dividend Restrictions					$ 0
Public Service Co Of Oklahoma [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					364,200,000	267,700,000
Maximum Loans to Money Pool					432,500,000	747,300,000
Average Borrowings from Money Pool					224,500,000	134,000,000
Average Loans to Money Pool					402,800,000	113,100,000
Net Loans (Borrowings) to/from Money Pool					(364,200,000)	(72,300,000)
Authorized Short Term Borrowing Limit					$ 400,000,000	$ 400,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.65%	0.34%		0.92%
Average Interest Rate For Funds Loaned					0.75%	0.07%		1.95%
Financing Activities (Textuals)
Interest Expense, Related Party					$ 5,500,000	$ 300,000		$ 600,000
Interest Income Earned on Advances to the Money Pool					300,000	0		100,000
Southwestern Electric Power Co [Member]
Long-term Debt
Senior Unsecured Notes					3,297,600,000	3,295,100,000
Notes Payable	[3]				55,900,000	59,100,000
Other Long-term Debt					38,100,000	41,000,000
Total Long-term Debt Outstanding					3,391,600,000	3,395,200,000
Outstanding Long-term Debt
Principal Amount, 2023					6,200,000
Principal Amount, 2024					6,200,000
Principal Amount, 2025					6,200,000
Principal Amount, 2026					906,200,000
Principal Amount, 2027					6,200,000
Principal Amount, After 2027					2,488,200,000
Principal Amount, Total					3,419,200,000
Unamortized Discount, Net and Debt Issuance Costs					(27,600,000)
Total Long-term Debt Outstanding					3,391,600,000	3,395,200,000
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues					194,000,000	153,000,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					2,283,200,000	2,126,000,000		1,735,300,000
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit					1,858,400,000	1,636,100,000		1,593,800,000
Financing Activities (Textuals)
Repayments of Long-term Debt					6,200,000	381,200,000		21,200,000
Proceeds from Issuance of Long-term Debt					$ 0	1,137,600,000		0
Maximum Percentage Debt to Capitalization					67.50%
Dividend Restrictions					$ 373,000,000
Dividends Paid on Common Stock					(3,400,000)	(4,800,000)		$ (1,900,000)
Southwestern Electric Power Co [Member] \| Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool					358,400,000	280,300,000
Maximum Loans to Money Pool					156,600,000	561,900,000
Average Borrowings from Money Pool					219,300,000	142,400,000
Average Loans to Money Pool					109,700,000	287,400,000
Net Loans (Borrowings) to/from Money Pool					(310,700,000)	153,800,000
Authorized Short Term Borrowing Limit					$ 400,000,000	$ 400,000,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					5.28%	0.48%		2.70%
Minimum Interest Rate					0.10%	0.02%		0.27%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed					2.80%	0.26%		1.27%
Average Interest Rate For Funds Loaned					0.55%	0.18%		0%
Southwestern Electric Power Co [Member] \| Utility [Member] \| Nonutility [Member]
Financing Activities (Textuals)
Interest Expense, Related Party					$ 4,900,000	$ 300,000		$ 1,500,000
Interest Income Earned on Advances to the Money Pool					$ 200,000	$ 100,000		$ 0
Southwestern Electric Power Co [Member] \| Nonutility [Member]
Maximum Interest Rate For Funds Loaned					5.28%	0.58%		2.70%
Minimum Interest Rate for Funds Loaned					0.46%	0.21%		0.27%
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Loans to Money Pool					$ 2,100,000	$ 2,100,000
Average Loans to Money Pool					2,100,000	2,100,000
Net Loans (Borrowings) to/from Money Pool					$ 2,100,000	$ 2,100,000
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Loaned					2.23%	0.37%		1.18%
Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2022
Maturity Date High					2052
Weighted Average Interest Rate					3.98%
Senior Notes [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.75%	0.61%
Senior Notes [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					8.13%	8.13%
Senior Notes [Member] \| AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2023
Maturity Date High					2052
Weighted Average Interest Rate					4.06%
Senior Notes [Member] \| AEP Texas Inc. [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.10%	2.10%
Senior Notes [Member] \| AEP Texas Inc. [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.76%	6.76%
Senior Notes [Member] \| AEP Transmission Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2023
Maturity Date High					2052
Weighted Average Interest Rate					3.83%
Senior Notes [Member] \| AEP Transmission Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.75%	2.75%
Senior Notes [Member] \| AEP Transmission Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					5.52%	5.52%
Senior Notes [Member] \| Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2025
Maturity Date High					2050
Weighted Average Interest Rate					4.68%
Senior Notes [Member] \| Appalachian Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.70%	2.70%
Senior Notes [Member] \| Appalachian Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					7%	7%
Senior Notes [Member] \| Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2023
Maturity Date High					2051
Weighted Average Interest Rate					4.19%
Senior Notes [Member] \| Indiana Michigan Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3.20%	3.20%
Senior Notes [Member] \| Indiana Michigan Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.05%	6.05%
Senior Notes [Member] \| Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2030
Maturity Date High					2051
Weighted Average Interest Rate					3.87%
Senior Notes [Member] \| Ohio Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					1.63%	1.63%
Senior Notes [Member] \| Ohio Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.60%	6.60%
Senior Notes [Member] \| Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2025
Maturity Date High					2051
Weighted Average Interest Rate					3.74%
Senior Notes [Member] \| Public Service Co Of Oklahoma [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.20%	2.20%
Senior Notes [Member] \| Public Service Co Of Oklahoma [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.63%	6.63%
Senior Notes [Member] \| Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2026
Maturity Date High					2051
Weighted Average Interest Rate					3.57%
Senior Notes [Member] \| Southwestern Electric Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					1.65%	1.65%
Senior Notes [Member] \| Southwestern Electric Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.20%	6.20%
Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]				2022
Maturity Date High	[13]				2036
Weighted Average Interest Rate					2.74%
Pollution Control Bonds [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.63%	0.19%
Pollution Control Bonds [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.55%	4.55%
Pollution Control Bonds [Member] \| AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]				2023
Maturity Date High	[13]				2030
Weighted Average Interest Rate					3.42%
Pollution Control Bonds [Member] \| AEP Texas Inc. [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.90%	0.90%
Pollution Control Bonds [Member] \| AEP Texas Inc. [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.55%	4.55%
Pollution Control Bonds [Member] \| Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]				2024
Maturity Date High	[13]				2036
Weighted Average Interest Rate					2.74%
Pollution Control Bonds [Member] \| Appalachian Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.63%	0.19%
Pollution Control Bonds [Member] \| Appalachian Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3.80%	2.75%
Pollution Control Bonds [Member] \| Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[13]				2025
Maturity Date High	[13]				2025
Weighted Average Interest Rate					2.49%
Pollution Control Bonds [Member] \| Indiana Michigan Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.75%	0.75%
Pollution Control Bonds [Member] \| Indiana Michigan Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3.05%	3.05%
Notes Payable, Other Payables [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2022
Maturity Date High					2032
Weighted Average Interest Rate					4.29%
Notes Payable, Other Payables [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.93%	0.79%
Notes Payable, Other Payables [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.37%	6.37%
Notes Payable, Other Payables [Member] \| Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2023
Maturity Date High					2027
Weighted Average Interest Rate					4.26%
Notes Payable, Other Payables [Member] \| Indiana Michigan Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					0.93%	0.79%
Notes Payable, Other Payables [Member] \| Indiana Michigan Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					5.93%	1.24%
Notes Payable, Other Payables [Member] \| Indiana Michigan Power Co [Member] \| Subsequent Event [Member]
Financing Activities (Textuals)
Repayments of Long-term Debt		$ 8,000,000		$ 8,000,000
Notes Payable, Other Payables [Member] \| Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2024
Maturity Date High					2032
Weighted Average Interest Rate					5.38%
Notes Payable, Other Payables [Member] \| Southwestern Electric Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.58%	4.58%
Notes Payable, Other Payables [Member] \| Southwestern Electric Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6.37%	6.37%
Securitization Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[14]				2023
Maturity Date High	[14]				2029
Weighted Average Interest Rate					2.91%
Securitization Bonds [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.01%	2.01%
Securitization Bonds [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3.77%	3.77%
Securitization Bonds [Member] \| AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[14]				2024
Maturity Date High	[14]				2029
Weighted Average Interest Rate					2.50%
Securitization Bonds [Member] \| AEP Texas Inc. [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.06%	2.06%
Securitization Bonds [Member] \| AEP Texas Inc. [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.84%	2.84%
Securitization Bonds [Member] \| AEP Texas Inc. [Member] \| Subsequent Event [Member]
Financing Activities (Textuals)
Repayments of Long-term Debt		12,000,000
Securitization Bonds [Member] \| Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[14]				2023
Maturity Date High	[14]				2028
Weighted Average Interest Rate					3.67%
Securitization Bonds [Member] \| Appalachian Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					2.01%	2.01%
Securitization Bonds [Member] \| Appalachian Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3.77%	3.77%
Securitization Bonds [Member] \| Appalachian Power Co [Member] \| Subsequent Event [Member]
Financing Activities (Textuals)
Repayments of Long-term Debt		$ 13,000,000
Junior Subordinated Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2024
Maturity Date High					2027
Weighted Average Interest Rate					2.35%
Junior Subordinated Notes [Member] \| 2019 Equity Units [Member]
Financing Activities (Textuals)
Proceeds from Issuance of Debt					$ 805,000,000
Principal Amounts of Junior Subordinated Debt					805,000,000
Junior Subordinated Notes [Member] \| 2020 Equity Units [Member]
Financing Activities (Textuals)
Proceeds from Issuance of Debt					850,000,000
Principal Amounts of Junior Subordinated Debt					$ 850,000,000
Junior Subordinated Notes [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					1.30%	1.30%
Junior Subordinated Notes [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3.88%	3.88%
Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2022
Maturity Date High					2059
Weighted Average Interest Rate					5.44%
Other Long Term Debt [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					1.15%	0.76%
Other Long Term Debt [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					13.72%	13.72%
Other Long Term Debt [Member] \| AEP Texas Inc. [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2025
Maturity Date High					2059
Weighted Average Interest Rate					5.67%
Other Long Term Debt [Member] \| AEP Texas Inc. [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.50%	1.35%
Other Long Term Debt [Member] \| AEP Texas Inc. [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					5.67%	4.50%
Other Long Term Debt [Member] \| Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2023
Maturity Date High					2026
Weighted Average Interest Rate					5.34%
Other Long Term Debt [Member] \| Appalachian Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.84%	1.24%
Other Long Term Debt [Member] \| Appalachian Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					13.72%	13.72%
Other Long Term Debt [Member] \| Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2025
Maturity Date High					2025
Weighted Average Interest Rate					6%
Other Long Term Debt [Member] \| Indiana Michigan Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6%	6%
Other Long Term Debt [Member] \| Indiana Michigan Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					6%	6%
Other Long Term Debt [Member] \| Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2028
Maturity Date High					2028
Weighted Average Interest Rate					1.15%
Other Long Term Debt [Member] \| Ohio Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					1.15%	1.15%
Other Long Term Debt [Member] \| Ohio Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					1.15%	1.15%
Other Long Term Debt [Member] \| Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2025
Maturity Date High					2027
Weighted Average Interest Rate					5.69%
Other Long Term Debt [Member] \| Public Service Co Of Oklahoma [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					3%	1.47%
Other Long Term Debt [Member] \| Public Service Co Of Oklahoma [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					5.75%	3%
Other Long Term Debt [Member] \| Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low					2028
Maturity Date High					2028
Weighted Average Interest Rate					4.68%
Other Long Term Debt [Member] \| Southwestern Electric Power Co [Member] \| Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.68%	4.68%
Other Long Term Debt [Member] \| Southwestern Electric Power Co [Member] \| Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate					4.68%	4.68%
Junior Subordinated Debt [Member]
Financing Activities (Textuals)
Debt Instrument, Interest Rate, Stated Percentage					2.031%
Junior Subordinated Debt [Member] \| 2019 Equity Units [Member]
Financing Activities (Textuals)
Debt Instrument, Interest Rate, Stated Percentage					3.40%
Junior Subordinated Debt [Member] \| 2020 Equity Units [Member]
Financing Activities (Textuals)
Debt Instrument, Interest Rate, Stated Percentage					1.30%
Senior Unsecured Notes \| Public Service Co Of Oklahoma [Member] \| Subsequent Event [Member]
Financing Activities (Textuals)
Proceeds from Issuance of Long-term Debt			$ 475,000,000
Debt Instrument, Interest Rate, Stated Percentage			5.25%
Servicing Contracts [Member] \| Appalachian Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					$ 9,400,000	$ 4,900,000	[15]	$ 5,200,000
Servicing Contracts [Member] \| Indiana Michigan Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					9,700,000	7,000,000	[15]	7,900,000
Servicing Contracts [Member] \| Ohio Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					29,800,000	8,300,000	[15]	24,100,000
Servicing Contracts [Member] \| Public Service Co Of Oklahoma [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					7,400,000	3,400,000	[15]	4,800,000
Servicing Contracts [Member] \| Southwestern Electric Power Co [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Revenue from Contracts with Customers					9,400,000	5,400,000	[15]	6,700,000
Retained Earnings [Member]
Financing Activities (Textuals)
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,						(1,100,000)
Dividends Paid on Common Stock					(1,600,000,000)	(1,500,000,000)		(1,400,000,000)
Additional Paid-in Capital [Member]
Financing Activities (Textuals)
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,					56,300,000	$ 32,600,000	[16]	$ (85,800,000)	[17]
Additional Paid-in Capital [Member] \| 2020 Equity Units [Member]
Financing Activities (Textuals)
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,					$ 121,000,000

[1]Reissued Treasury Stock used to fulfill share commitments related to AEP’s Equity Units. See “Equity Units” section below for additional information.[2]For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.[3]Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.[4]Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.[5]See “Equity Units” section below for additional information.[6]Amount includes $805 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.[7]Amount includes $850 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.[8]Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.[9]Weighted-average rate as of December 31, 2022 and 2021, respectively.[10]Includes the restrictions of consolidated and non-consolidated subsidiaries.[11]Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.[12]Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.[13]Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.[14]Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.[15]In 2021, due to the successful collection of accounts receivable balances during the COVID-19 pandemic, the allowance for doubtful accounts was reduced, resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.[16]Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.[17](b)

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Stock Based Compensation (Textuals)
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		10,000,000
Number of Shares Remaining Available for Issuance Under the AEP Long-Term Incentive Plan		5,249,391
Reduction in Aggregate Common Shares Authorized Per Share Issued Pursuant to Stock Options or Stock Appreciation Rights		0.286
Performance Units and AEP Career Shares Reinvested Dividends Portion For [Member]
Performance Units
Awarded Units	[1]	63,300	74,500	73,400
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology
Weighted Average Grant Date Fair Value		$ 98.73	$ 84.48	$ 84.87
Stock Based Compensation [Member]
Compensation Cost and Actual Tax Benefit Realized for the Tax Deductions from Compensation Cost for Share-based Payment Arrangements
Compensation Cost for Share-based Payment Arrangements	[2]	$ 63.3	$ 61.1	$ 53.8
Actual Tax Benefit Realized		8	8.7	7.2
Total Compensation Cost Capitalized		16	$ 16.9	$ 20.4
Stock Based Compensation (Textuals)
Total Unrecognized Compensation Cost Related to Unvested Share-based Compensation Arrangements Granted		$ 78
Weighted-average Period of Unrecognized Compensation Costs (in years)		1 year 4 months 28 days
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Stock Based Compensation (Textuals)
Number of Years After Termination of Board Service Participant Can Elect to Have Stock Units Paid in Cash		10 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology
Weighted Average Grant Date Fair Value		$ 95.16	$ 84.54	$ 83.80
Awarded Units		14,500	12,600	12,100
Restricted Stock Units (RSUs) [Member]
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 17.8	$ 20.5	$ 22.9
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	[3]	$ 20.3	$ 22	$ 25.2
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		424,300
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 84.86
Shares/Units, Vested		(209,000)
Weighted Average Grant Date Fair Value, Vested		$ 85.15
Shares/Units, Forfeited		(46,100)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 85.80
Nonvested, Shares/Units, Ending Balance		459,600	424,300
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 88.05	$ 84.86
Stock Based Compensation (Textuals)
Maximum Contractual Term of Outstanding Restricted Stock Units (in months)		40 months
Total Aggregate Intrinsic Value of Nonvested Shares		$ 44
Weighted Average Remaining Contractual Life of Nonvested Shares (in years)		1 year 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology
Weighted Average Grant Date Fair Value		$ 90.48	$ 80.39	$ 94.38
Awarded Units		290,400	280,000	268,700
Performance Units [Member]
Performance Units
Awarded Units		530,300	565,000	424,800
Vesting Period (in years)		3 years	3 years	3 years
Certified Performance Scores and Units Earned
Certified Performance Score		131.10%	102.90%	128.20%
Performance Units Earned		512,660	537,166	757,858
Performance Units Manditorily Deferred as AEP Career Shares		28,282	14,613	13,614
Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program		23,609	22,915	26,936
Share Based Compensation Performance Units to be Settled in Shares	[4]	460,769	499,638	717,308
Cash Payouts
Equity Payouts for Performance Units		$ 43.2	$ 54.7	$ 75.4
Stock Based Compensation (Textuals)
Performance Score by HR Committee, Lower Range		0%
Performance Score by HR Committee, Higher Range		200%
Equity Payouts For Career Share Distributions		$ 5.1	$ 4	$ 1.9
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	[5]	2 years 10 months 9 days	2 years 10 months 17 days	2 years 10 months 13 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum		25.92%	25.87%	13.67%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum		40.82%	39.90%	28.15%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate		1.64%	0.19%	1.40%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	[6]	0%	0%	0%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Weighted Average Volatility Rate		31.09%	31.01%	16.39%
Weighted Average Grant Date Fair Value		$ 97.61	$ 81.02	$ 116.56
Performance Units and Reinvested Dividends [Member]
Share Based Compensation Performance Units Converted to Shares	[7]	461,000
Performance Units
Awarded Units		45,500
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		923,800
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 96.15
Shares/Units, Vested	[7]	(395,800)
Weighted Average Grant Date Fair Value, Vested		$ 116.06
Shares/Units, Forfeited		(91,600)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 84.81
Nonvested, Shares/Units, Ending Balance		1,012,200	923,800
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 90.27	$ 96.15
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology
Weighted Average Grant Date Fair Value		$ 98.73

[1]The vesting period for the reinvested dividends on performance shares is equal to the remaining life of the related performance shares. Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends.[2]Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.[3]Intrinsic value is calculated as market price at the vesting date.[4]Performance shares settled in AEP common stock in the quarter following the end of the year shown.[5]Period from award date to vesting date.[6]Equivalent to reinvesting dividends.[7]The vested Performance Shares will be converted to 461 thousand shares based on the closing share price on the day before settlement.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Affiliated Revenues and Purchases
Affiliated Revenues		$ 0	$ 0	$ 0
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		$ 73,339,100	68,304,100
AEP Wind Holdings LLC PPAs [Abstract]
Equity Method Investment, Ownership Percentage		50%
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		$ 75,000
Rockport Plant, Unit 2 [Member]
Related Party Transactions (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		100%
BP Wind Energy [Member]
AEP Wind Holdings LLC PPAs [Abstract]
Equity Method Investment, Ownership Percentage		50%
Generation and Marketing [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 18,000	55,400	104,600
Generation and Marketing [Member] \| BP Wind Energy [Member]
AEP Wind Holdings LLC PPAs [Abstract]
Equity Method Investment, Ownership Percentage		50%
Appalachian Power Co. to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		$ 2,500	2,400	900
Indiana Michigan Power Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals)
Percentage of Power Sold under Unit Power Agreement		30%
AEP Generating Co to Indiana Michigan Power Co [Member]
Cook Coal Terminal
Coal Transloading Services		$ 9,000	11,000	12,000
Railcar Maintenance		$ 600	300	900
AEP Generating Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals)
Percentage of Power Sold under Unit Power Agreement		30%
AEP Generating Co to Public Service Co of Oklahoma [Member]
Cook Coal Terminal
Railcar Maintenance		$ 600	400	700
AEP Generating Co To Southwestern Electric Power Co [Member]
Cook Coal Terminal
Railcar Maintenance		2,700	2,800	3,000
AEP Energy Partners, Inc. to AEP Texas Inc. [Member]
Oklaunion PPA between AEP Texas and AEPEP
Oklaunion Purchase Power Agreement				88,000
Indiana Michigan Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		6,100	4,800	3,000
Kentucky Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		600	500	400
Ohio Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		5,200	4,600	4,500
Public Service Co of Oklahoma to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		100	400	400
Wheeling Power Co to AEP Transmission Co [Member]
Joint License Agreement
Joint License Agreement		200	200	200
AEP Generating Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		$ 11,300	7,600	10,600
AEP Generating Co [Member] \| Rockport Plant, Unit 2 [Member]
Related Party Transactions (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
AEP Generating Co [Member] \| AEP Generating Co to Indiana Michigan Power Co [Member] \| Rockport Plant, Unit 2 [Member]
Related Party Transactions (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		100%
AEP Transmission Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 1,354,500	1,171,500	954,600
Revenue from Related Parties, Net		1,283,800	1,153,900	896,300
Sales and Purchases of Property
Related Party Sales of Property		2,300	1,400	200
Related Party Purchases of Property		11,600	16,700	6,000
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		13,339,900	12,101,000
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		11,100
AEP Transmission Co [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
AEP Transmission Co [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
AEP Transmission Co [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
AEP Transmission Co [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1,276,400	1,136,100	885,000
AEP Transmission Co [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		7,400	17,800	11,300
AEP Transmission Co [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0
Appalachian Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		256,100	197,900	174,700
Transmission Service Charges
PJM Net Transmission Service Charges		345,100	302,000	243,200
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		36,100	40,100	43,700
Sales and Purchases of Property
Related Party Sales of Property		16,000	6,200	5,700
Related Party Purchases of Property		2,400	1,000	1,300
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		12,379,200	11,804,300
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		12,500
Appalachian Power Co [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		169,700	128,600	112,500
Appalachian Power Co [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]			5,300
Appalachian Power Co [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Appalachian Power Co [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		77,500	60,300	49,100
Appalachian Power Co [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		8,900	9,000	7,800
Appalachian Power Co [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0
Indiana Michigan Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		15,300	3,800	10,500
Cost of Purchased Power from Affiliate		241,800	217,900	172,800
Transmission Service Charges
PJM Net Transmission Service Charges		220,800	186,700	145,900
Sales and Purchases of Property
Related Party Sales of Property		5,300	7,000	1,500
Related Party Purchases of Property		2,000	600	3,400
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		7,411,500	7,310,900
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		$ 11,000
Indiana Michigan Power Co [Member] \| Rockport Plant, Unit 2 [Member]
Related Party Transactions (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
Indiana Michigan Power Co [Member] \| Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	$ 0	0	0
Indiana Michigan Power Co [Member] \| Auction Purchases From AEP Energy [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]		0	0
Indiana Michigan Power Co [Member] \| Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]			0
Indiana Michigan Power Co [Member] \| Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		241,800	217,900	172,800
Indiana Michigan Power Co [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Indiana Michigan Power Co [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]			3,100
Indiana Michigan Power Co [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Indiana Michigan Power Co [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		7,700	(2,500)	2,900
Indiana Michigan Power Co [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	7,600	6,300	4,500
Indiana Michigan Power Co [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0
Indiana Michigan Power Co [Member] \| AEP Wind Holdings LLC [Member] \| Generation and Marketing [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		12,000	10,000	11,000
Kentucky Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		2,000	3,100	3,200
Related Party Transactions (Textuals)
Capacity Sales		199
Ohio Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		18,800	24,800	41,500
Cost of Purchased Power from Affiliate		9,800	51,900	119,700
Transmission Service Charges
PJM Net Transmission Service Charges		608,200	508,900	417,400
Sales and Purchases of Property
Related Party Sales of Property		7,600	9,200	7,000
Related Party Purchases of Property		2,000	1,400	1,200
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		8,609,300	7,963,000
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		8,100
Ohio Power Co [Member] \| Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]	9,800	26,600	51,000
Ohio Power Co [Member] \| Auction Purchases From AEP Energy [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]		25,300	58,700
Ohio Power Co [Member] \| Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]			10,000
Ohio Power Co [Member] \| Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0	0
Ohio Power Co [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Ohio Power Co [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Ohio Power Co [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Ohio Power Co [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(3,600)	(1,100)	16,600
Ohio Power Co [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		22,400	25,900	24,900
Ohio Power Co [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0
Ohio Power Co [Member] \| AEP Wind Holdings LLC [Member] \| Generation and Marketing [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		24,000	20,000	23,000
Public Service Co Of Oklahoma [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		2,900	4,200	5,200
Transmission Service Charges
SPP Net Transmission Service Charges		110,800	94,700	69,700
Sales and Purchases of Property
Related Party Sales of Property		2,500	500	1,100
Related Party Purchases of Property		7,600	300	400
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		5,626,500	4,802,800
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		5,800
Public Service Co Of Oklahoma [Member] \| OKTCo Radial Asset Transfer [Member] \| Net Book Value of Radial Assets [Member]
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net			60,000
Public Service Co Of Oklahoma [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Public Service Co Of Oklahoma [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Public Service Co Of Oklahoma [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Public Service Co Of Oklahoma [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Public Service Co Of Oklahoma [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		2,900	4,200	5,200
Public Service Co Of Oklahoma [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0
Southwestern Electric Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		59,500	41,400	41,000
Revenue from Related Parties, Net		53,900	41,000	39,000
Transmission Service Charges
SPP Net Transmission Service Charges		62,100	56,200	31,300
Sales and Purchases of Property
Related Party Sales of Property		1,000	400	800
Related Party Purchases of Property		2,800	300	2,800
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		8,262,200	7,400,100
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		8,800
Southwestern Electric Power Co [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
Southwestern Electric Power Co [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Southwestern Electric Power Co [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
Southwestern Electric Power Co [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		51,500	39,600	37,400
Southwestern Electric Power Co [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1,100	1,400	1,600
Southwestern Electric Power Co [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1,300
Southwestern Electric Power Co [Member] \| AEP Wind Holdings LLC [Member] \| Generation and Marketing [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		14,000	14,000	14,000
Wheeling Power Co [Member] [Domain]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		4,700	3,200	3,300
AEP Texas Inc. [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		3,500	3,900	90,800
ERCOT Transmission Service Charges
Billings from ETT for ERCOT Wholesale Transmission Services		28,000	28,000	28,000
Sales and Purchases of Property
Related Party Sales of Property		3,000	400	900
Related Party Purchases of Property		1,300	400	1,500
Related Party Transactions (Textuals)
Total Property, Plant and Equipment, Net		11,681,600	10,635,400
Charitable Contribution to AEP Foundation [Abstract]
Related Party Charitable Contribuions to AEP Foundation		$ 9,900
AEP Texas Inc. [Member] \| Oklaunion Generating Station [Member]
Related Party Transactions (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		54.69%
AEP Texas Inc. [Member] \| Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 0	0	0
AEP Texas Inc. [Member] \| Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				0
AEP Texas Inc. [Member] \| Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues				87,500
AEP Texas Inc. [Member] \| Transmission Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0	0
AEP Texas Inc. [Member] \| Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		3,500	$ 3,900	$ 3,300
AEP Texas Inc. [Member] \| Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 0

[1]Refer to the Ohio Auctions section below for further information regarding these amounts.[2]I&M’s affiliated revenues exclude capacity sales to KPCo from Rockport Plant, Unit 2 and barging, urea transloading and other transportation services to affiliates. See sections “Unit Power Agreements” and “I&M Barging, Urea Transloading and Other Services” below for additional information.

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions		12 Months Ended
Variable Interest Entities (Details) $ in Millions		Dec. 31, 2022 USD ($) MW		Dec. 31, 2021 USD ($)		Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
ASSETS
Current Assets		$ 6,775.5		$ 4,984.4
Net Property, Plant and Equipment		73,339.1		68,304.1
Other Noncurrent Assets		13,288.7		14,380.2
Total Assets		93,403.3		87,668.7
LIABILITIES AND EQUITY
Current Liabilities		13,266.3		10,906.4
Noncurrent Liabilities		55,968.7		54,038.8
Equity		24,122.4		22,680.2		$ 20,774.5	$ 19,913.2
Total Liabilities and Equity		93,403.3		87,668.7
Variable Interest Entities (Textuals)
Securitization Bonds		487.8		603.5
Securitized Assets		$ 446		552.8
Equity Method Investment, Ownership Percentage		50%
Equity Method Investments		$ 1,276.7		1,447.5		1,406.3
Equity Method Investment Income		109.4		(91.7)		(91.1)
Generation and Marketing [Member]
ASSETS
Total Assets		4,520.1		4,263.6
Variable Interest Entities (Textuals)
Equity Method Investments		337.6		487.8		467
Equity Method Investment Income		192.4		10.6		(3.2)
Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		2,031.6		2,000.1
Protected Cell Of Energy Insurance Services, Inc. [Member]
Variable Interest Entities (Textuals)
Insurance Premium Expense to Protected Cell		31		30		31
Protected Cell Of Energy Insurance Services, Inc. [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		194.5		217.3
Net Property, Plant and Equipment		0		0
Other Noncurrent Assets		0.3		0
Total Assets		194.8		217.3
LIABILITIES AND EQUITY
Current Liabilities		46.4		37.5
Noncurrent Liabilities		79.1		82.3
Equity		69.3		97.5
Total Liabilities and Equity		$ 194.8		217.3
Transource Energy [Member]
Variable Interest Entities (Textuals)
Debt-to-Total Capitalization Maximum		67.50%
Transource Energy [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 23.5		38.8
Net Property, Plant and Equipment		482.3		475.4
Other Noncurrent Assets		2.7		3
Total Assets		508.5		517.2
LIABILITIES AND EQUITY
Current Liabilities		22.8		12.5
Noncurrent Liabilities		218.6		216.9
Equity		267.1		287.8
Total Liabilities and Equity		508.5		517.2
Trent and Desert Sky Wind Farms [Member] \| Generation and Marketing [Member]
Variable Interest Entities (Textuals)
Redeemable Noncontrolling Interest		63
Apple Blossom and Black Oak [Member]
Variable Interest Entities (Textuals)
Noncontrolling Interest in Variable Interest Entity		94		108
HLBV Income for Noncontrolling Interests		$ 9		7
Long-term PPA Energy Production		100%
Apple Blossom and Black Oak [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 8.3		9.9
Net Property, Plant and Equipment		216.5		217.3
Other Noncurrent Assets		13.6		11.3
Total Assets		238.4		238.5
LIABILITIES AND EQUITY
Current Liabilities		4.5		6.6
Noncurrent Liabilities		5.4		5.2
Equity		228.5		226.7
Total Liabilities and Equity		238.4		238.5
Santa Rita East [Member]
Variable Interest Entities (Textuals)
Noncontrolling Interest in Variable Interest Entity		58		59
Production Tax Credits		$ 24		25		$ 23
Equity Ownership Percentage		85%
Equity Ownership Percentage		85%
Santa Rita East [Member] \| Generation and Marketing [Member]
Variable Interest Entities (Textuals)
Percentage of an Asset Acquired		85%				10%
WindGenerationMWs \| MW		302
Santa Rita East [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 21.3		7.6
Net Property, Plant and Equipment		421.6		437.6
Other Noncurrent Assets		0.1		0
Total Assets		443		445.2
LIABILITIES AND EQUITY
Current Liabilities		9.6		5.8
Noncurrent Liabilities		7.3		7
Equity		426.1		432.4
Total Liabilities and Equity		$ 443		445.2
AEP Credit, Inc.
Variable Interest Entities (Textuals)
Minimum Percentage of Equity AEP Provides		5%
Percentage Of Short Term Borrowing Needs In Excess Of Third Party Financings		25%
AEP Credit, Inc. \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 1,181		996.6
Net Property, Plant and Equipment		0		0
Other Noncurrent Assets		9		10.4
Total Assets		1,190		1,007
LIABILITIES AND EQUITY
Current Liabilities		1,087.8		953.1
Noncurrent Liabilities		0.9		0.9
Equity		101.3		53
Total Liabilities and Equity		1,190		1,007
Dolet Hills Lignite Co, LLC [Member]
Variable Interest Entities (Textuals)
Equity Method Investment Income		$ (1.4)		(3.4)		$ (2.9)
Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
AEP's Ownership In OVEC		43.47%
Approximate OVEC Generating Capacity (MWs) \| MW		2,400
Intercompany Power Agreement End Date		2040
Outstanding Indebtedness		$ 1,100		1,100
Dry Lake Solar Project [Member]
Variable Interest Entities (Textuals)
Noncontrolling Interest in Variable Interest Entity		$ 34		35
Percentage of an Asset Acquired		75%
Dry Lake Solar Project [Member] \| Generation and Marketing [Member]
Variable Interest Entities (Textuals)
Solar Generation MWs \| MW		100
Dry Lake Solar Project [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 4		4
Net Property, Plant and Equipment		142.6		146.1
Other Noncurrent Assets		0.3		0.3
Total Assets		146.9		150.4
LIABILITIES AND EQUITY
Current Liabilities		1		0.9
Noncurrent Liabilities		0.7		0.6
Equity		145.2		148.9
Total Liabilities and Equity		$ 146.9		150.4
Joint Venture Wind Farms [Member]
Variable Interest Entities (Textuals)
Long-term PPA Energy Production		100%
Rockport Generating Plant (Unit No. 2) [Member]
Variable Interest Entities (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		100%
Capital Contribution From Parent [Member] \| Ohio Valley Electric Corporation [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		$ 4.4		4.4
Maximum Exposure		4.4		4.4
Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		12,345.6		11,667.1		10,687.8	9,900.9
AEP's Ratio of OVEC Debt [Member] \| Ohio Valley Electric Corporation [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet	[1]	0		0
Maximum Exposure	[1]	478.2		492
Total Investment [Member] \| Ohio Valley Electric Corporation [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		4.4		4.4
Maximum Exposure		$ 482.6		496.4
Long-term PPA MWs [Member] \| Santa Rita East [Member]
Variable Interest Entities (Textuals)
WindGenerationMWs \| MW		260
Sold at Wholesale MWs [Member] \| Santa Rita East [Member]
Variable Interest Entities (Textuals)
WindGenerationMWs \| MW		42
Great Plains Energy Inc. [Member] \| Transource Energy [Member]
Variable Interest Entities (Textuals)
Equity and Voting Ownership Percentage		13.50%
Cleco Power, LLC [Member]
Variable Interest Entities (Textuals)
Percentage of VIE Sales of Lignite Produced		50%
AEP Transmission Co [Member]
ASSETS
Current Assets		$ 188.7		165
Net Property, Plant and Equipment		13,339.9		12,101
Other Noncurrent Assets		285.6		258.4
Total Assets		13,814.2		12,524.4
LIABILITIES AND EQUITY
Current Liabilities		1,368		1,273.9
Noncurrent Liabilities		6,573.2		5,874.4
Total Liabilities and Equity		13,814.2		12,524.4
AEP Transmission Co [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		0.3		0.1
AEP Transmission Co [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		286.6		267.1		270.3
AEP Transmission Co [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		31.6		23.3
Maximum Exposure		31.6		23.3
Appalachian Power Co [Member]
ASSETS
Current Assets		1,259.6		925.3
Net Property, Plant and Equipment		12,379.2		11,804.3
Other Noncurrent Assets		1,583.4		1,359.3
Total Assets		15,222.2		14,088.9
LIABILITIES AND EQUITY
Current Liabilities		1,390.2		1,415.9
Noncurrent Liabilities		8,856.6		8,025.1
Equity		4,975.4		4,647.9		4,344.3	4,172.4
Total Liabilities and Equity		15,222.2		14,088.9
Variable Interest Entities (Textuals)
Securitization Bonds		173.3		198.8
Securitized Assets		159.6		185.1
Amount Of Power Purchased From OVEC		119.3		104.3		94.4
Appalachian Power Co [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		29.4		23.3
Appalachian Power Co [Member] \| Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals)
Securitized Assets		160		185
Appalachian Power Co [Member] \| Appalachian Consumer Rate Relief Funding [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		13.5		16
Net Property, Plant and Equipment		0		0
Other Noncurrent Assets		164.6	[2]	187.8	[3]
Total Assets		178.1		203.8
LIABILITIES AND EQUITY
Current Liabilities		29.3		29
Noncurrent Liabilities		146.9		172.9
Equity		1.9		1.9
Total Liabilities and Equity		$ 178.1		203.8
Appalachian Power Co [Member] \| Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
Power Participation Ratio		15.69%
Outstanding Indebtedness		$ 173		177
Appalachian Power Co [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		347.5		313.3		294.9
Appalachian Power Co [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		41.5		44.1
Maximum Exposure		41.5		44.1
Appalachian Power Co [Member] \| Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		2,891.1		2,534.4		2,248	2,078.3
Appalachian Power Co [Member] \| Other Noncurrent Assets [Member] \| Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals)
Intercompany Item Eliminated in Consolidation		2		2
Appalachian Power Co [Member] \| Current Liabilities [Member] \| Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		26		26
Appalachian Power Co [Member] \| Noncurrent Liabilities [Member] \| Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		147		173
Indiana Michigan Power Co [Member]
ASSETS
Current Assets		571.8		439.4
Net Property, Plant and Equipment		7,411.5		7,310.9
Other Noncurrent Assets		4,135.6		4,657.9
Total Assets		12,118.9		12,408.2
LIABILITIES AND EQUITY
Current Liabilities		1,197.1		894
Noncurrent Liabilities		7,913.5		8,729.5
Equity		3,008.3		2,784.7		2,749.2	2,544.4
Total Liabilities and Equity		12,118.9		12,408.2
Variable Interest Entities (Textuals)
Amount Of Power Purchased From OVEC		59.7		52.2		47.2
Indiana Michigan Power Co [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		78.7		23.3
Indiana Michigan Power Co [Member] \| DCC Fuel [Member]
Variable Interest Entities (Textuals)
Payments Made by I&M to DCC Fuel		$ 84		91		94
Capital Lease Term		54 months
Indiana Michigan Power Co [Member] \| DCC Fuel [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 90.2		65.2
Net Property, Plant and Equipment		179.1		118.6
Other Noncurrent Assets		94		57.2
Total Assets		363.3		241
LIABILITIES AND EQUITY
Current Liabilities		90		65.1
Noncurrent Liabilities		273.3		175.9
Equity		0		0
Total Liabilities and Equity		$ 363.3		241
Indiana Michigan Power Co [Member] \| Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
Power Participation Ratio		7.85%
Outstanding Indebtedness		$ 86		89
Indiana Michigan Power Co [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		192.4		200.9		210.2
Indiana Michigan Power Co [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		27.7		21.8
Maximum Exposure		27.7		21.8
Indiana Michigan Power Co [Member] \| Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals)
Billings from VIE		242		218		173
Indiana Michigan Power Co [Member] \| Carrying Amount in AEP Generating Company's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		$ 17		18
Indiana Michigan Power Co [Member] \| Rockport Generating Plant
Variable Interest Entities (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
Indiana Michigan Power Co [Member] \| Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		$ 1,963.2		1,748.5		1,718.7	1,518.5
Ohio Power Co [Member]
ASSETS
Current Assets		414.4		327.5
Net Property, Plant and Equipment		8,609.3		7,963
Other Noncurrent Assets		979.4		975.3
Total Assets		10,003.1		9,265.8
LIABILITIES AND EQUITY
Current Liabilities		1,635.5		1,245.7
Noncurrent Liabilities		5,279.5		5,173.8
Equity		3,088.1		2,846.3		2,692.7	2,508.5
Total Liabilities and Equity		10,003.1		9,265.8
Variable Interest Entities (Textuals)
Amount Of Power Purchased From OVEC		151.8		133		120.8
Equity Method Investment Income		(0.6)		0		0
Ohio Power Co [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		$ 9.8		9.8
Ohio Power Co [Member] \| Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
AEP's Ownership In OVEC		4.30%
Power Participation Ratio		19.93%
Outstanding Indebtedness		$ 219		226
Ohio Power Co [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		272.5		234.9		232.8
Ohio Power Co [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		31.1		25.5
Maximum Exposure		31.1		25.5
Ohio Power Co [Member] \| Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		1,929.1		1,686.3		1,532.7	1,348.5
Public Service Co Of Oklahoma [Member]
ASSETS
Current Assets		491.5		386.8
Net Property, Plant and Equipment		5,626.5		4,802.8
Other Noncurrent Assets		847.9		1,209.4
Total Assets		6,965.9		6,399
LIABILITIES AND EQUITY
Current Liabilities		842.7		562.7
Noncurrent Liabilities		3,704.1		3,544.7
Equity		2,419.1		2,291.6		1,545.6	1,373.3
Total Liabilities and Equity		6,965.9		6,399
Public Service Co Of Oklahoma [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		5		5.3
Public Service Co Of Oklahoma [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		142.3		123.7		113.2
Public Service Co Of Oklahoma [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		17.7		13.7
Maximum Exposure		17.7		13.7
Public Service Co Of Oklahoma [Member] \| Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		1,218		1,095.4		974.3	851
Southwestern Electric Power Co [Member]
ASSETS
Current Assets		812.2		668.5
Net Property, Plant and Equipment		8,262.2		7,400.1
Other Noncurrent Assets		1,304.4		1,257.1
Total Assets		10,378.8		9,325.7
LIABILITIES AND EQUITY
Current Liabilities		947.7		538.7
Noncurrent Liabilities		5,756.3		5,637.2
Equity		3,674.8		3,149.8		2,627.7	2,441.1
Total Liabilities and Equity		10,378.8		9,325.7
Variable Interest Entities (Textuals)
Equity Method Investment Income		(1.4)		(3.4)		(2.9)
Southwestern Electric Power Co [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		9.3		53.9
Southwestern Electric Power Co [Member] \| Sabine Mining Co [Member]
Variable Interest Entities (Textuals)
Billings from VIE		168		162		131
Guarantees Of Mine Reclamation Amount		155
Estimated Final Cost Mine Reclamation		135
Amount Collected, Rider Mine Close Other Assets Noncurrent		33
Amount Collected Through Rider For Final Mine Closure And Reclamation Costs		89
Amount Collected, Rider Mine Close ARO Noncurrent		$ 122
Mine End-of-Life Date		2023
Reclamation Complete Date		2037
Southwestern Electric Power Co [Member] \| Sabine Mining Co [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		$ 108.3		77.2
Net Property, Plant and Equipment		7.2		51.8
Other Noncurrent Assets		130		104.1
Total Assets		245.5		233.1
LIABILITIES AND EQUITY
Current Liabilities		25.4		18.9
Noncurrent Liabilities		219.4		214.3
Equity		0.7		(0.1)
Total Liabilities and Equity		$ 245.5		233.1
Southwestern Electric Power Co [Member] \| Dolet Hills Lignite Co, LLC [Member]
Variable Interest Entities (Textuals)
Billings from VIE				47		142
Percentage of VIE Sales of Lignite Produced		50%
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO		50%
Percentage of Management Fee Received by SWEPCo from DHLC		100%
Equity Method Investment Income		$ (1.4)		(3.4)		(2.9)
Dividends		25		0		0
Southwestern Electric Power Co [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		192.5		168.6		161.8
Southwestern Electric Power Co [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		23.8		20.5
Maximum Exposure		23.8		20.5
Southwestern Electric Power Co [Member] \| Capital Contribution From Parent [Member] \| Dolet Hills Lignite Co, LLC [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		7.6		7.6
Maximum Exposure		7.6		7.6
Southwestern Electric Power Co [Member] \| Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		2,236		2,050.9		1,811.9	1,629.5
Southwestern Electric Power Co [Member] \| Retained Earnings [Member] \| Dolet Hills Lignite Co, LLC [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		0.4		23.8
Maximum Exposure		0.4		23.8
Southwestern Electric Power Co [Member] \| SWEPCo's Share of Obligations [Member] \| Dolet Hills Lignite Co, LLC [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		0		0
Maximum Exposure		36.8		50.3
Southwestern Electric Power Co [Member] \| Total Investment [Member] \| Dolet Hills Lignite Co, LLC [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		8		31.4
Maximum Exposure		$ 44.8		81.7
AEP Generating Co [Member] \| Rockport Generating Plant
Variable Interest Entities (Textuals)
Jointly Owned Utility Plant, Proportionate Ownership Share		50%
Transource Energy [Member]
Variable Interest Entities (Textuals)
Equity and Voting Ownership Percentage		86.50%
AEP Texas Inc. [Member]
ASSETS
Current Assets		$ 446.9		347.2
Net Property, Plant and Equipment		11,681.6		10,635.4
Other Noncurrent Assets		763.7		854.1
Total Assets		12,892.2		11,836.7
LIABILITIES AND EQUITY
Current Liabilities		1,043.8		1,311.7
Noncurrent Liabilities		7,944.1		6,930.8
Equity		3,904.3		3,594.2		3,206	2,961.1
Total Liabilities and Equity		12,892.2		11,836.7
Variable Interest Entities (Textuals)
Securitization Bonds		314.4		404.7
Securitized Assets		286.4		367.6
AEP Texas Inc. [Member] \| Unregulated Operation [Member]
ASSETS
Net Property, Plant and Equipment		1.2		1.2
AEP Texas Inc. [Member] \| AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals)
Securitized Assets		125		184
AEP Texas Inc. [Member] \| AEP Texas Central Transition Funding Co [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		27		24.9
Net Property, Plant and Equipment		0		0
Other Noncurrent Assets		140.9	[4]	208.3	[5]
Total Assets		167.9		233.2
LIABILITIES AND EQUITY
Current Liabilities		73.2		71.2
Noncurrent Liabilities		90.4		157.8
Equity		4.3		4.2
Total Liabilities and Equity		167.9		233.2
AEP Texas Inc. [Member] \| Restoration Funding [Member]
Variable Interest Entities (Textuals)
Securitized Assets		161		183
AEP Texas Inc. [Member] \| Restoration Funding [Member] \| Variable Interest Entities [Member]
ASSETS
Current Assets		21.1		24.3
Net Property, Plant and Equipment		0		0
Other Noncurrent Assets		168.8	[6]	192.6	[7]
Total Assets		189.9		216.9
LIABILITIES AND EQUITY
Current Liabilities		31.3		36.1
Noncurrent Liabilities		157.4		179.6
Equity		1.2		1.2
Total Liabilities and Equity		189.9		216.9
AEP Texas Inc. [Member] \| Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals)
Billings from VIE		236.8		206.9		199.4
AEP Texas Inc. [Member] \| Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures
As Reported on the Balance Sheet		27.8		22.2
Maximum Exposure		27.8		22.2
AEP Texas Inc. [Member] \| Retained Earnings [Member]
LIABILITIES AND EQUITY
Equity		2,354.7		2,046.8		1,757	$ 1,516
AEP Texas Inc. [Member] \| Other Noncurrent Assets [Member] \| AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals)
Intercompany Item Eliminated in Consolidation		16		24
AEP Texas Inc. [Member] \| Other Noncurrent Assets [Member] \| Restoration Funding [Member]
Variable Interest Entities (Textuals)
Intercompany Item Eliminated in Consolidation		7		8
AEP Texas Inc. [Member] \| Current Liabilities [Member] \| AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		70		68
AEP Texas Inc. [Member] \| Current Liabilities [Member] \| Restoration Funding [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		24		23
AEP Texas Inc. [Member] \| Noncurrent Liabilities [Member] \| AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		71		141
AEP Texas Inc. [Member] \| Noncurrent Liabilities [Member] \| Restoration Funding [Member]
Variable Interest Entities (Textuals)
Securitization Bonds		$ 150		173
Parent Company [Member] \| Ohio Valley Electric Corporation [Member]
Variable Interest Entities (Textuals)
AEP's Ownership In OVEC		39.17%
Joint Venture Wind Farms [Member]
Variable Interest Entities (Textuals)
Equity Method Investment, Ownership Percentage		50%
Production Tax Credits		$ 39		33		36
Equity Method Investments		247		399
Equity Method Investment Income		194		12		(2)
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 62		(3)
Berkshire Hathaway [Member]
Variable Interest Entities (Textuals)
Equity Method Investment, Ownership Percentage		50%
AEP Transmission Holdco [Member]
Variable Interest Entities (Textuals)
Equity Method Investment, Ownership Percentage		50%
BP Wind Energy [Member]
Variable Interest Entities (Textuals)
Equity Method Investment, Ownership Percentage		50%
BP Wind Energy [Member] \| Generation and Marketing [Member]
Variable Interest Entities (Textuals)
Equity Method Investment, Ownership Percentage		50%
ETT [Member]
Variable Interest Entities (Textuals)
Equity Method Investments		$ 762		733
Equity Method Investment Income		$ (74)		$ (66)		$ (68)

[1] Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $173 million, $86 million and $219 million Includes an intercompany item eliminated in consolidation of $2 million . Includes an intercompany item eliminated in consolidation of $16 million Includes an intercompany item eliminated in consolidation of $24 million. Includes an intercompany item eliminated in consolidation of $7 million .

Property, Plant and Equipment_3

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 25,834.2		$ 24,319.6
Property, Plant and Equipment, Transmission		33,266.9		30,816.3
Property, Plant and Equipment, Distribution		27,138.8		25,457.4
Property, Plant and Equipment, Other		5,971.8		5,844.9
Property, Plant and Equipment, Construction Work in Progress		4,809.7		3,786.8
Accumulated Depreciation		23,682.3		21,920.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		73,339.1		68,304.1
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[2],[3],[4],[5],[6]	2,741.7		2,516.7
Accretion Expense	[1],[2],[3],[4],[5],[6]	111.2		105
Liabilities Incurred	[1],[2],[3],[4],[5],[6]	37.4		22.8
Liabilities Settled	[1],[2],[3],[4],[5],[6]	(47)		(41.4)
Revisions in Cash Flow Estimates	[1],[2],[3],[4],[5],[6],[7]	100.3		138.6
Ending Balance	[1],[2],[3],[4],[5],[6]	2,943.6		2,741.7		$ 2,516.7
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant		2,000		1,930
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		133.7		139.7		148.1
Allowance for Borrowed Funds Used During Construction		63		53.8		66
Jointly-owned Electric Facilities
Utility Plant in Service		2,626		2,589.4
Construction Work in Progress		21.5		16.5
Accumulated Depreciation		1,096.1		947.4
Asset Impairments and Other Related Charges		48.8		11.6		0
AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission		6,301.5		5,849.9
Property, Plant and Equipment, Distribution		5,312.8		4,917.2
Property, Plant and Equipment, Other		1,022.8		961.1
Property, Plant and Equipment, Construction Work in Progress		805.2		551.3
Accumulated Depreciation		1,760.7		1,644.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		11,681.6		10,635.4
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3]	4.4		4.6
Accretion Expense	[2],[3]	0.3		0.2
Liabilities Incurred	[2],[3]	0		0
Liabilities Settled	[2],[3]	(0.2)		(0.4)
Revisions in Cash Flow Estimates	[2],[3],[7]	0		0
Ending Balance	[2],[3]	4.5		4.4		4.6
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		19.7		21.5		19.4
Allowance for Borrowed Funds Used During Construction		11.5		10.5		12.5
AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission		12,335.4		11,031
Property, Plant and Equipment, Other		476.8		451.9
Property, Plant and Equipment, Construction Work in Progress		1,554.7		1,402.2
Accumulated Depreciation		1,027		784.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		13,339.9		12,101
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		70.7		67.2		74
Allowance for Borrowed Funds Used During Construction		22.4		21		25.5
Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		6,776.8		6,683.9
Property, Plant and Equipment, Transmission		4,482.8		4,322.4
Property, Plant and Equipment, Distribution		4,933		4,683.3
Property, Plant and Equipment, Other		883.3		696.6
Property, Plant and Equipment, Construction Work in Progress		705.3		469.9
Accumulated Depreciation		5,402		5,051.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		12,379.2		11,804.3
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3]	404.6		313.1
Accretion Expense	[2],[3]	15.8		13.7
Liabilities Incurred	[2],[3]	3		0
Liabilities Settled	[2],[3]	(12.7)		(6.9)
Revisions in Cash Flow Estimates	[2],[3],[7]	17		84.7
Ending Balance	[2],[3]	427.7		404.6		313.1
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		11.7		15.6		14.6
Allowance for Borrowed Funds Used During Construction		6.5		7.5		7.9
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges		24.9		0		0
Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		5,585.1		5,531.8
Property, Plant and Equipment, Transmission		1,842.2		1,783.1
Property, Plant and Equipment, Distribution		3,024.7		2,800.1
Property, Plant and Equipment, Other		839.3		792.9
Property, Plant and Equipment, Construction Work in Progress		253		302.8
Accumulated Depreciation		4,132.8		3,899.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		7,411.5		7,310.9
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3],[4]	1,946.3		1,813.8
Accretion Expense	[2],[3],[4]	71.5		72.9
Liabilities Incurred	[2],[3],[4]	3.2		0.3
Liabilities Settled	[2],[3],[4]	(0.6)		(0.1)
Revisions in Cash Flow Estimates	[2],[3],[4],[7]	7.7		59.4
Ending Balance	[2],[3],[4]	2,028.1		1,946.3		1,813.8
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant		2,000		1,930
Fair Value of Legally Restricted Assets		3,010		3,540
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		9.8		12.8		11.5
Allowance for Borrowed Funds Used During Construction		5.7		5.1		5.7
Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission		3,198.6		2,992.8
Property, Plant and Equipment, Distribution		6,450.3		6,070.6
Property, Plant and Equipment, Other		1,051.4		992.9
Property, Plant and Equipment, Construction Work in Progress		474.3		365
Accumulated Depreciation		2,565.3		2,458.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,609.3		7,963
Asset Retirement Obligations (ARO)
Beginning Balance	[2]	1.9		1.9
Accretion Expense	[2]	0.2		0.1
Liabilities Incurred	[2]	3		0
Liabilities Settled	[2]	(0.1)		(0.1)
Revisions in Cash Flow Estimates	[2],[7]	0		0
Ending Balance	[2]	5		1.9		1.9
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		13.9		10.8		12.5
Allowance for Borrowed Funds Used During Construction		6.7		4.7		6.2
Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		2,394.8		1,802.4
Property, Plant and Equipment, Transmission		1,164.4		1,107.7
Property, Plant and Equipment, Distribution		3,216.4		3,004.9
Property, Plant and Equipment, Other		469.3		437
Property, Plant and Equipment, Construction Work in Progress		219.3		156
Accumulated Depreciation		1,837.7		1,705.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,626.5		4,802.8
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3],[6]	57.6		47.4
Accretion Expense	[2],[3],[6]	4.1		3.3
Liabilities Incurred	[2],[3],[6]	12.8		7.6
Liabilities Settled	[2],[3],[6]	(0.7)		(0.7)
Revisions in Cash Flow Estimates	[2],[3],[6],[7]	1.9		0
Ending Balance	[2],[3],[6]	75.7		57.6		47.4
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		1.5		2.4		4
Allowance for Borrowed Funds Used During Construction		2.7		0.7		2
Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		5,476.2		4,734.5
Property, Plant and Equipment, Transmission		2,479.8		2,316.9
Property, Plant and Equipment, Distribution		2,659.6		2,514.3
Property, Plant and Equipment, Other		804.4		764
Property, Plant and Equipment, Construction Work in Progress		369.5		240.7
Accumulated Depreciation		3,527.3		3,170.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		8,262.2		7,400.1
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[2],[3],[6]	222.7		222.1
Accretion Expense	[1],[2],[3],[6]	11.9		9.8
Liabilities Incurred	[1],[2],[3],[6]	15.4		9.2
Liabilities Settled	[1],[2],[3],[6]	(25.8)		(20.9)
Revisions in Cash Flow Estimates	[1],[2],[3],[6],[7]	56.7		2.5
Ending Balance	[1],[2],[3],[6]	280.9		222.7		222.1
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		4.9		7		7.7
Allowance for Borrowed Funds Used During Construction		4.3		3		3.9
Jointly-owned Electric Facilities
Utility Plant in Service		3,692.8		2,965.6
Construction Work in Progress		31.6		16.5
Accumulated Depreciation		1,131.3		952.8
Asset Impairments and Other Related Charges		$ 0		$ 11.6		$ 0
Flint Creek Generating Station (Unit No. 1) [Member] \| Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	50%		50%
Utility Plant in Service	[8]	$ 382.9		$ 377.6
Construction Work in Progress	[8]	16.4		6.3
Accumulated Depreciation	[8]	$ 149.4		$ 133.5
Flint Creek Generating Station (Unit No. 1) [Member] \| Southwestern Electric Power Co [Member] \| Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	50%		50%
Utility Plant in Service	[8]	$ 382.9		$ 377.6
Construction Work in Progress	[8]	16.4		6.3
Accumulated Depreciation	[8]	$ 149.4		$ 133.5
Pirkey Generating Station (Unit No. 1) [Member] \| Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	85.90%		85.90%
Utility Plant in Service	[8]	$ 632		$ 613.8
Construction Work in Progress	[8]	0		0
Accumulated Depreciation	[8]	$ 632		$ 528.3
Pirkey Generating Station (Unit No. 1) [Member] \| Southwestern Electric Power Co [Member] \| Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	85.90%		85.90%
Utility Plant in Service	[8]	$ 632		$ 613.8
Construction Work in Progress	[8]	0		0
Accumulated Depreciation	[8]	$ 632		$ 528.3
Turk Generating Plant [Member] \| Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	73.30%		73.30%
Utility Plant in Service	[8]	$ 1,611.1		$ 1,598
Construction Work in Progress	[8]	5.1		10.2
Accumulated Depreciation	[8]	$ 314.7		$ 285.6
Turk Generating Plant [Member] \| Southwestern Electric Power Co [Member] \| Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	73.30%		73.30%
Utility Plant in Service	[8]	$ 1,611.1		$ 1,598
Construction Work in Progress	[8]	5.1		10.2
Accumulated Depreciation	[8]	$ 314.7		$ 285.6
Rockport Generating Plant (Unit No. 2) [Member]
Jointly-owned Electric Facilities
Percent of Ownership		100%
NCWF [Member] \| Public Service Co Of Oklahoma [Member]
Jointly-owned Electric Facilities
Percent of Ownership		45.50%
NCWF [Member] \| Public Service Co Of Oklahoma [Member] \| Wind [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[9],[10]	45.50%		45.50%
Utility Plant in Service	[9],[10]	$ 889.3		$ 313.7
Construction Work in Progress	[9],[10]	9.1		0
Accumulated Depreciation	[9],[10]	$ 28.1		$ 4.2
NCWF [Member] \| Southwestern Electric Power Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		54.50%
NCWF [Member] \| Southwestern Electric Power Co [Member] \| Wind [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[9],[10]	54.50%		54.50%
Utility Plant in Service	[9],[10]	$ 1,066.8		$ 376.2
Construction Work in Progress	[9],[10]	10.1		0
Accumulated Depreciation	[9],[10]	$ 35.2		$ 5.4
Rockport Generating Plant \| Indiana Michigan Power Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		50%
Rockport Generating Plant \| Indiana Michigan Power Co [Member] \| Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[11],[12],[13]	50%		50%
Utility Plant in Service	[11],[12],[13]	$ 1,357.4		$ 1,247.2
Construction Work in Progress	[11],[12],[13]	9.2		13.9
Accumulated Depreciation	[11],[12],[13]	$ 905.1		794.5
Rockport Generating Plant \| AEP Generating Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		50%
Regulated Operation [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	[14]	$ 23,759.7		22,428.3
Property, Plant and Equipment, Transmission		33,221.7		30,771.1
Property, Plant and Equipment, Distribution		27,138.8		25,457.4
Property, Plant and Equipment, Other		5,528.9		5,403.5
Property, Plant and Equipment, Construction Work in Progress	[14]	4,776.4		3,734.8
Accumulated Depreciation		23,118		21,491.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 71,307.5		$ 66,304
Regulated Operation [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		132 years		132 years		132 years
Depreciable Life Ranges - Transmission		75 years		75 years		75 years
Depreciable Life Ranges - Distribution		78 years		80 years		78 years
Depreciable Life Ranges - Other		75 years		75 years		75 years
Regulated Operation [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		20 years		20 years		20 years
Depreciable Life Ranges - Transmission		24 years		15 years		15 years
Depreciable Life Ranges - Distribution		7 years		7 years		7 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| Generation [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		7.60%		7.80%		6.30%
Regulated Operation [Member] \| Generation [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.70%		2.70%
Regulated Operation [Member] \| Transmission [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.60%		2.60%
Regulated Operation [Member] \| Transmission [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2%		2%		2%
Regulated Operation [Member] \| Distribution [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.60%		3.60%		3.70%
Regulated Operation [Member] \| Distribution [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.80%		2.70%
Regulated Operation [Member] \| Other Property Class [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		14.40%		12.50%		11.30%
Regulated Operation [Member] \| Other Property Class [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		3%		2.80%
Regulated Operation [Member] \| AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 0		$ 0
Property, Plant and Equipment, Transmission		6,301.5		5,849.9
Property, Plant and Equipment, Distribution		5,312.8		4,917.2
Property, Plant and Equipment, Other		1,020.4		958.7
Property, Plant and Equipment, Construction Work in Progress		805.2		551.3
Accumulated Depreciation		1,759.5		1,642.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 11,680.4		$ 10,634.2
Regulated Operation [Member] \| AEP Texas Inc. [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission		75 years		75 years		75 years
Depreciable Life Ranges - Distribution		70 years		70 years		70 years
Depreciable Life Ranges - Other		50 years		50 years		50 years
Regulated Operation [Member] \| AEP Texas Inc. [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission		50 years		50 years		50 years
Depreciable Life Ranges - Distribution		7 years		7 years		7 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| AEP Texas Inc. [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.20%		2.20%		2%
Regulated Operation [Member] \| AEP Texas Inc. [Member] \| Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.90%		2.90%		3.10%
Regulated Operation [Member] \| AEP Texas Inc. [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.20%		5.80%		6.10%
Regulated Operation [Member] \| AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 0		$ 0
Property, Plant and Equipment, Transmission		12,335.4		11,031
Property, Plant and Equipment, Distribution		0		0
Property, Plant and Equipment, Other		476.6		451.7
Property, Plant and Equipment, Construction Work in Progress		1,554.7		1,402.2
Accumulated Depreciation		1,027.1		784
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 13,339.6		$ 12,100.9
Regulated Operation [Member] \| AEP Transmission Co [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission		75 years		75 years		75 years
Depreciable Life Ranges - Other		56 years		56 years		64 years
Regulated Operation [Member] \| AEP Transmission Co [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission		24 years		24 years		24 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| AEP Transmission Co [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.60%		2.50%		2.40%
Regulated Operation [Member] \| AEP Transmission Co [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.60%		6.70%		6.30%
Regulated Operation [Member] \| Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 6,776.8		$ 6,683.9
Property, Plant and Equipment, Transmission		4,482.8		4,322.4
Property, Plant and Equipment, Distribution		4,933		4,683.3
Property, Plant and Equipment, Other		849.2		668.9
Property, Plant and Equipment, Construction Work in Progress		705.3		469.9
Accumulated Depreciation		5,397.3		5,047.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 12,349.8		$ 11,781
Regulated Operation [Member] \| Appalachian Power Co [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		118 years		118 years		118 years
Depreciable Life Ranges - Transmission		75 years		75 years		75 years
Depreciable Life Ranges - Distribution		57 years		57 years		57 years
Depreciable Life Ranges - Other		55 years		55 years		55 years
Regulated Operation [Member] \| Appalachian Power Co [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		35 years		35 years
Depreciable Life Ranges - Transmission		24 years		15 years		15 years
Depreciable Life Ranges - Distribution		12 years		12 years		12 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| Appalachian Power Co [Member] \| Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.60%		3.60%		3.30%
Regulated Operation [Member] \| Appalachian Power Co [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.20%		2.10%		2.20%
Regulated Operation [Member] \| Appalachian Power Co [Member] \| Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.60%		3.50%		3.70%
Regulated Operation [Member] \| Appalachian Power Co [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		7.30%		8.50%		7.80%
Regulated Operation [Member] \| Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 5,534.6		$ 5,531.8
Property, Plant and Equipment, Transmission		1,842.2		1,783.1
Property, Plant and Equipment, Distribution		3,024.7		2,800.1
Property, Plant and Equipment, Other		796.1		755.1
Property, Plant and Equipment, Construction Work in Progress		253		302.8
Accumulated Depreciation		4,117.8		3,885.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 7,332.8		$ 7,287.6
Regulated Operation [Member] \| Indiana Michigan Power Co [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		132 years		132 years		132 years
Depreciable Life Ranges - Transmission		67 years		70 years		70 years
Depreciable Life Ranges - Distribution		71 years		71 years		71 years
Depreciable Life Ranges - Other		45 years		51 years		51 years
Regulated Operation [Member] \| Indiana Michigan Power Co [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		20 years		20 years		20 years
Depreciable Life Ranges - Transmission		44 years		45 years		45 years
Depreciable Life Ranges - Distribution		14 years		14 years		14 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| Indiana Michigan Power Co [Member] \| Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		4.90%		4.70%		4.60%
Regulated Operation [Member] \| Indiana Michigan Power Co [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.50%		2.40%		2.30%
Regulated Operation [Member] \| Indiana Michigan Power Co [Member] \| Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		3.40%		3.40%
Regulated Operation [Member] \| Indiana Michigan Power Co [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		10.10%		9%		10.20%
Regulated Operation [Member] \| Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 0		$ 0
Property, Plant and Equipment, Transmission		3,198.6		2,992.8
Property, Plant and Equipment, Distribution		6,450.3		6,070.6
Property, Plant and Equipment, Other		1,040.6		982.2
Property, Plant and Equipment, Construction Work in Progress		474.3		365
Accumulated Depreciation		2,564.3		2,457.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 8,599.5		$ 7,953.2
Regulated Operation [Member] \| Ohio Power Co [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission		60 years		60 years		60 years
Depreciable Life Ranges - Distribution		70 years		70 years		65 years
Depreciable Life Ranges - Other		50 years		50 years		50 years
Regulated Operation [Member] \| Ohio Power Co [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Transmission		39 years		39 years		39 years
Depreciable Life Ranges - Distribution		11 years		11 years		14 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| Ohio Power Co [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.30%		2.30%
Regulated Operation [Member] \| Ohio Power Co [Member] \| Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.90%		3.10%
Regulated Operation [Member] \| Ohio Power Co [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.10%		6.10%		5%
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 2,394.8		$ 1,802.4
Property, Plant and Equipment, Transmission		1,164.4		1,107.7
Property, Plant and Equipment, Distribution		3,216.4		3,004.9
Property, Plant and Equipment, Other		466		433.5
Property, Plant and Equipment, Construction Work in Progress		219.3		156
Accumulated Depreciation		1,839.4		1,707
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 5,621.5		$ 4,797.5
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		75 years		75 years		75 years
Depreciable Life Ranges - Transmission		75 years		75 years		75 years
Depreciable Life Ranges - Distribution		78 years		78 years		78 years
Depreciable Life Ranges - Other		56 years		56 years		64 years
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		30 years		30 years		35 years
Depreciable Life Ranges - Transmission		42 years		42 years		45 years
Depreciable Life Ranges - Distribution		15 years		15 years		15 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member] \| Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		2.80%		3.10%
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.50%		2.40%		2.20%
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member] \| Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.90%		2.90%		2.90%
Regulated Operation [Member] \| Public Service Co Of Oklahoma [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.80%		6.10%		5.70%
Regulated Operation [Member] \| Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	[14]	$ 5,476.2		$ 4,734.5
Property, Plant and Equipment, Transmission		2,479.8		2,316.9
Property, Plant and Equipment, Distribution		2,659.6		2,514.3
Property, Plant and Equipment, Other		582.6		542
Property, Plant and Equipment, Construction Work in Progress	[14]	369.5		240.7
Accumulated Depreciation		3,314.8		3,002.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 8,252.9		$ 7,346.2
Regulated Operation [Member] \| Southwestern Electric Power Co [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		65 years		65 years		65 years
Depreciable Life Ranges - Transmission		70 years		74 years		73 years
Depreciable Life Ranges - Distribution		75 years		80 years		67 years
Depreciable Life Ranges - Other		57 years		58 years		52 years
Regulated Operation [Member] \| Southwestern Electric Power Co [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		30 years		30 years		35 years
Depreciable Life Ranges - Transmission		44 years		49 years		47 years
Depreciable Life Ranges - Distribution		15 years		15 years		15 years
Depreciable Life Ranges - Other		5 years		5 years		5 years
Regulated Operation [Member] \| Southwestern Electric Power Co [Member] \| Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.70%		2.70%
Regulated Operation [Member] \| Southwestern Electric Power Co [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.40%		2.30%
Regulated Operation [Member] \| Southwestern Electric Power Co [Member] \| Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.90%		2.80%		2.70%
Regulated Operation [Member] \| Southwestern Electric Power Co [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		9%		8.60%		8.50%
Unregulated Operation [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 2,031.6		$ 2,000.1
Unregulated Operation [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		61 years		59 years		59 years
Depreciable Life Ranges - Transmission		62 years		40 years		40 years
Depreciable Life Ranges - Other		35 years	[15]	35 years	[15]	50 years
Unregulated Operation [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		3 years		10 years		15 years
Depreciable Life Ranges - Transmission		10 years		30 years		30 years
Depreciable Life Ranges - Other		5 years	[15]	5 years	[15]	5 years
Unregulated Operation [Member] \| Generation [Member] \| Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		8.70%		10.40%		4%
Unregulated Operation [Member] \| Generation [Member] \| Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.80%		3.80%		3.60%
Unregulated Operation [Member] \| Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.80%		2.60%		2.50%
Unregulated Operation [Member] \| Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		25.20%		16.50%		16.10%
Unregulated Operation [Member] \| AEP Texas Inc. [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 1.2		$ 1.2
Unregulated Operation [Member] \| AEP Transmission Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0.3		0.1
Unregulated Operation [Member] \| Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		29.4		23.3
Unregulated Operation [Member] \| Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		78.7		23.3
Unregulated Operation [Member] \| Ohio Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9.8		9.8
Unregulated Operation [Member] \| Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5		5.3
Unregulated Operation [Member] \| Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9.3		53.9
Glen Lyn Station [Member] \| Appalachian Power Co [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates				79
Cook Nuclear Plant [Member] \| Indiana Michigan Power Co [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates				58
Amos Plant \| Appalachian Power Co [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates		14
Traverse [Member] \| Public Service Co Of Oklahoma [Member]
Asset Retirement Obligations (ARO)
Liabilities Incurred		13
Traverse [Member] \| Southwestern Electric Power Co [Member]
Asset Retirement Obligations (ARO)
Liabilities Incurred		15
Pirkey Power Plant \| Southwestern Electric Power Co [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates		13
Sabine Mining Co [Member] \| Southwestern Electric Power Co [Member]
Property, Plant and Equipment (Textuals)
Asset Retirement Obligation, Revision of Estimate, Estimated Reclamation Costs - 1		16
Asset Retirement Obligation, Revision of Estimate, Estimated Reclamation Costs - 2		7
Pirkey Power Plant \| Southwestern Electric Power Co [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates		14
Generation and Marketing [Member]
Jointly-owned Electric Facilities
Asset Impairments and Other Related Charges		$ 0		$ 0

[1]Includes ARO related to Sabine and DHLC.[2]Includes ARO related to asbestos removal.[3]Includes ARO related to ash disposal facilities.[4]Includes ARO related to nuclear decommissioning costs for the Cook Plant of $2 billion and $1.93 billion as of December 31, 2022 and 2021, respectively.[5]Includes ARO related to solar farms.[6]Includes ARO related to wind farms.[7]Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.[8]Operated by SWEPCo.[9]Operated by PSO.[10]PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Sundance was placed into service in April 2021. Maverick was placed into service in September 2021. Traverse was placed into service in March 2022. See the “Acquisitions” section of Note 7 for additional information.[11]AEGCo owns 50%.[12]Amounts include I&M's 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 was subject to a finance lease with a nonaffiliated company. In December 2022, the lease expired at which point I&M and AEGCo acquired 100% of the interests in Unit 2. See the "Rockport Plant Litigation" section of Note 6 for additional information.[13]Operated by I&M.[14]AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.[15]In 2020 management announced plans to retire the Pirkey Plant in 2023 and the related depreciable lives have been adjusted accordingly. See Note 5 - Effects of Regulation for additional information.

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Disaggregation of Revenue
Revenue from Contracts with Customers		$ 19,639.5		$ 16,792		$ 14,918.5
Revenue, Performance Obligation
Fixed Performance Obligations		437
Revenues		19,639.5		16,792		14,918.5
Revenue Textuals
Revenue from Related Parties		0		0		0
Redemption of Noncontrolling Interest		0		0		(100.2)
2022 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		85.5
2023-2024 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		157.3
2025-2026 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		133.9
After 2026 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		60.3
Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		14,453.1		12,157.6		11,364
Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		6,995.9		6,090.8		5,693.7
Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		3,941.7		3,289.7		3,064.8
Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		3,254.2	[1]	2,562.6		2,407.4
Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		261.3		214.5		198.1
Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		4,440.8		4,014.5		3,209.7
Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,229.5		1,080.5		720.2
Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,380.2	[2]	1,178.3	[3]	1,051.8	[4]
Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		121.1	[1]	83.3	[5]	59.3	[6]
Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,710	[1]	1,672.4	[7]	1,378.4	[8]
Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		497.8	[9]	350.9	[5]	289.6	[6]
Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		19,391.7		16,523		14,863.3
Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		247.8		269		55.2
Alternative [Member]
Revenue, Performance Obligation
Revenues		(112.5)	[10]	41.4	[11]	(6.3)	[12]
Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		408.2		367.4		305.6
Revenue, Performance Obligation
Revenues		360.3	[1],[13]	227.6	[5],[14]	61.5	[6],[15]
AEP Texas Inc. [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,848		1,587.7		1,528
Revenue, Performance Obligation
Revenues		1,846.8		1,593.8		1,618.9
Current Assets
Affiliated Companies - Contracts with Customers		11.9		7.9
Revenue Textuals
Revenue from Related Parties		3.5		3.9		90.8
AEP Texas Inc. [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		0.1		0.4
AEP Texas Inc. [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,259.6		1,049		1,079.9
AEP Texas Inc. [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		667.2		550.3		563.6
AEP Texas Inc. [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		417.5		358.5		366.7
AEP Texas Inc. [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		139.6	[16]	108.9		120.1
AEP Texas Inc. [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		35.3		31.3		29.5
AEP Texas Inc. [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		563.8		497.5		399.9
AEP Texas Inc. [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[17]	0	[18]	0	[19]
AEP Texas Inc. [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		563.8	[20]	497.5	[21]	399.9	[22]
AEP Texas Inc. [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		24.6	[23]	41.2	[24]	48.2	[25]
AEP Texas Inc. [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(1.2)		6.1		90.9
AEP Texas Inc. [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(1.2)	[26]	6.1	[27]	3.4	[28]
AEP Texas Inc. [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		3.6		3.5		3.2
Revenue, Performance Obligation
Revenues		0	[16]	0	[29]	87.5	[30]
AEP Transmission Co [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,651.7		1,410.9		1,232.7
Revenue, Performance Obligation
Revenues		1,624.5		1,469.3		1,145.7
Current Assets
Affiliated Companies - Contracts with Customers		119.5		97.3
Revenue Textuals
Revenue from Related Parties		1,354.5		1,171.5		954.6
AEP Transmission Co [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		113.8		95.5
AEP Transmission Co [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Co [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Co [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Co [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[16]	0		0
AEP Transmission Co [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Co [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,643.5		1,393.9		1,210.3
AEP Transmission Co [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[17]	0	[18]	0	[19]
AEP Transmission Co [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,643.5	[20]	1,393.9	[21]	1,210.3	[22]
Revenue Textuals
Revenue from Related Parties		1,300		1,100		952
AEP Transmission Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		8.2	[23]	17	[24]	22.4	[25]
AEP Transmission Co [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(27.2)		58.4		(87)
AEP Transmission Co [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(27.2)	[26]	58.4	[27]	(87)	[28]
AEP Transmission Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(0.2)		0.3		0.6
Revenue, Performance Obligation
Revenues		0	[16]	0	[29]	0	[30]
Appalachian Power Co [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		3,520.7		3,092.9		2,809.2
Revenue, Performance Obligation
Fixed Performance Obligations		83.2
Revenues		3,519.9		3,105.2		2,796.2
Current Assets
Affiliated Companies - Contracts with Customers		94		129.9
Revenue Textuals
Revenue from Related Parties		256.1		197.9		174.7
Appalachian Power Co [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		64.5		117.8
Appalachian Power Co [Member] \| 2022 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		16.1
Appalachian Power Co [Member] \| 2023-2024 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		32.2
Appalachian Power Co [Member] \| 2025-2026 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		23.2
Appalachian Power Co [Member] \| After 2026 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		11.7
Appalachian Power Co [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,953.2		2,591		2,388.7
Appalachian Power Co [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,558.7		1,379.6		1,250.6
Appalachian Power Co [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		643.4		556.3		517
Appalachian Power Co [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		664	[16]	584.3		553.5
Appalachian Power Co [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		87.1		70.8		67.6
Appalachian Power Co [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		466.9		431.5		361
Appalachian Power Co [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		299.9	[17]	302.7	[18]	230.2	[19]
Revenue Textuals
Revenue from Related Parties		170		129		112
Appalachian Power Co [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		167	[20]	128.8	[21]	130.8	[22]
Revenue Textuals
Revenue from Related Parties		78
Appalachian Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		100.6	[23]	70.4	[24]	59.5	[25]
Appalachian Power Co [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(0.8)		12.3		(13)
Appalachian Power Co [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(1.3)	[26]	12.3	[27]	(13)	[28]
Appalachian Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		18.3		11.8		10.6
Revenue, Performance Obligation
Revenues		0.5	[16]	0	[29]	0	[30]
Indiana Michigan Power Co [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,659.7		2,330.7		2,236
Revenue, Performance Obligation
Fixed Performance Obligations		27.5
Revenues		2,669.6		2,326.7		2,241.8
Current Assets
Affiliated Companies - Contracts with Customers		104		78.2
Revenue Textuals
Revenue from Related Parties		15.3		3.8		10.5
Indiana Michigan Power Co [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		75.3		61.2
Indiana Michigan Power Co [Member] \| 2022 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		4.6
Indiana Michigan Power Co [Member] \| 2023-2024 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		9.2
Indiana Michigan Power Co [Member] \| 2025-2026 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		9.2
Indiana Michigan Power Co [Member] \| After 2026 [Member]
Revenue, Performance Obligation
Fixed Performance Obligations		4.5
Indiana Michigan Power Co [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,010.5		1,874.8		1,847.4
Indiana Michigan Power Co [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		852.4		805.4		794.1
Indiana Michigan Power Co [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		550.2		507.2		499.3
Indiana Michigan Power Co [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		602.9	[16]	557		547.4
Indiana Michigan Power Co [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		5		5.2		6.6
Indiana Michigan Power Co [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		526.8		351.8		303.6
Indiana Michigan Power Co [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		490	[17]	318.1	[18]	274.6	[19]
Indiana Michigan Power Co [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		36.8	[20]	33.7	[21]	29	[22]
Indiana Michigan Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		122.4	[23]	104.1	[24]	85	[25]
Indiana Michigan Power Co [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		9.9		(4)		5.8
Indiana Michigan Power Co [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		10	[26]	(4)	[27]	5.8	[28]
Indiana Michigan Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		11.7		7.7		5.2
Revenue, Performance Obligation
Revenues		(0.1)	[16]	0	[29]	0	[30]
Revenue Textuals
Revenue from Related Parties		62		60		69
Ohio Power Co [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		3,672.1		2,837.5		2,665
Revenue, Performance Obligation
Revenues		3,665.1		2,899.1		2,749.1
Current Assets
Affiliated Companies - Contracts with Customers		100.9		71.8
Revenue Textuals
Revenue from Related Parties		18.8		24.8		41.5
Ohio Power Co [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		49.9		51.7
Ohio Power Co [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		3,363.5		2,609.5		2,488.5
Ohio Power Co [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,830.2		1,587.9		1,523.4
Ohio Power Co [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		947.7		722.7		682
Ohio Power Co [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		571.7	[16]	286.3		270
Ohio Power Co [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		13.9		12.6		13.1
Ohio Power Co [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		86.2		74.9		67
Ohio Power Co [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[17]	0	[18]	0	[19]
Ohio Power Co [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		86.2	[20]	74.9	[21]	67	[22]
Ohio Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		222.4	[23]	153.1	[24]	109.5	[25]
Ohio Power Co [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(7)		61.6		84.1
Ohio Power Co [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(25.6)	[26]	42.6	[27]	66.6	[28]
Ohio Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		11		10.6		9
Revenue, Performance Obligation
Revenues		18.6	[16]	19	[29]	17.5	[30]
Public Service Co Of Oklahoma [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,875.7		1,474.3		1,263.9
Revenue, Performance Obligation
Revenues		1,874.7		1,474.4		1,266.1
Current Assets
Affiliated Companies - Contracts with Customers		52.2		35
Revenue Textuals
Revenue from Related Parties		2.9		4.2		5.2
Public Service Co Of Oklahoma [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		18.8		18.8
Public Service Co Of Oklahoma [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,780.9		1,382.6		1,186.6
Public Service Co Of Oklahoma [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		816.3		651.9		579.4
Public Service Co Of Oklahoma [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		489.2		378.9		320.1
Public Service Co Of Oklahoma [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		372.5	[16]	274.1		221.1
Public Service Co Of Oklahoma [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		102.9		77.7		66
Public Service Co Of Oklahoma [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		65.7		60.4		42.6
Public Service Co Of Oklahoma [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		26.5	[17]	22.9	[18]	15.1	[19]
Public Service Co Of Oklahoma [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		39.2	[20]	37.5	[21]	27.5	[22]
Public Service Co Of Oklahoma [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		29.1	[23]	31.3	[24]	34.7	[25]
Public Service Co Of Oklahoma [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(1)		0.1		2.2
Public Service Co Of Oklahoma [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(1)	[26]	0.1	[27]	2.2	[28]
Public Service Co Of Oklahoma [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		6.2		4.9		14.8
Revenue, Performance Obligation
Revenues		0	[16]	0	[29]	0	[30]
Southwestern Electric Power Co [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,283.2		2,126		1,735.3
Revenue, Performance Obligation
Revenues		2,284.4		2,131.8		1,738.5
Current Assets
Affiliated Companies - Contracts with Customers		65.4		38.3
Revenue Textuals
Revenue from Related Parties		59.5		41.4		41
Southwestern Electric Power Co [Member] \| Short-term Contract with Customer [Member]
Current Assets
Affiliated Companies - Contracts with Customers		19.1		24.7
Southwestern Electric Power Co [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,836.6		1,593.2		1,435.4
Southwestern Electric Power Co [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		820.7		709.5		630.8
Southwestern Electric Power Co [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		612.3		529.3		466.7
Southwestern Electric Power Co [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		393.5	[16]	344.4		328.8
Southwestern Electric Power Co [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		10.1		10		9.1
Southwestern Electric Power Co [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		421.9		509.3		273.2
Southwestern Electric Power Co [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		273.2	[17]	386.6	[18]	162	[19]
Southwestern Electric Power Co [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		148.7	[20]	122.7	[21]	111.2	[22]
Revenue Textuals
Revenue from Related Parties		51
Southwestern Electric Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		24.7	[23]	23.5	[24]	26.7	[25]
Southwestern Electric Power Co [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		1.2		5.8		3.2
Southwestern Electric Power Co [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		1.2	[26]	5.8	[27]	3.2	[28]
Southwestern Electric Power Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1.9		1.9		2.9
Revenue, Performance Obligation
Revenues		0	[16]	0	[29]	0	[30]
Consolidation Eliminations [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Revenue, Performance Obligation
Revenues		(1,603.8)		(1,461.5)		(1,328)
Revenue Textuals
Revenue from Related Parties		(1,603.8)		(1,461.5)		(1,328)
Consolidation Eliminations [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(0.9)		(0.8)		(0.7)
Consolidation Eliminations [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Consolidation Eliminations [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Consolidation Eliminations [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(0.9)	[1]	(0.8)		(0.7)
Consolidation Eliminations [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Consolidation Eliminations [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(1,431.3)		(1,261.2)		(1,111.3)
Consolidation Eliminations [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Consolidation Eliminations [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(1,413.2)	[2]	(1,206)	[3]	(1,006.7)	[4]
Consolidation Eliminations [Member] \| Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(8)	[1]	(3.6)	[5]	(1.6)	[6]
Consolidation Eliminations [Member] \| Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(10.1)	[1]	(51.6)	[7]	(103)	[8]
Consolidation Eliminations [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(104.8)	[9]	(115.2)	[5]	(148.6)	[6]
Consolidation Eliminations [Member] \| Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		(1,537)		(1,377.2)		(1,260.6)
Consolidation Eliminations [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(66.8)		(84.3)		(67.4)
Consolidation Eliminations [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(57.7)	[10]	(73.6)	[11]	7.5	[12]
Consolidation Eliminations [Member] \| Other Revenues [Member]
Revenue, Performance Obligation
Revenues		(9.1)	[1],[13]	(10.7)	[5],[14]	(74.9)	[6],[15]
Consolidation Eliminations [Member] \| AEP Transmission Co [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Revenue, Performance Obligation
Revenues		0		0		0
Revenue Textuals
Revenue from Related Parties		0		0		0
Consolidation Eliminations [Member] \| AEP Transmission Co [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Vertically Integrated Utilities [Member]
Revenue, Performance Obligation
Revenues		11,477.5		9,998.5		8,879.4
Revenue Textuals
Revenue from Related Parties		184.7		146.3		126.2
Vertically Integrated Utilities [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		9,831.1		8,499.9		7,796.6
Vertically Integrated Utilities [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		4,498.6		3,952.6		3,606.8
Vertically Integrated Utilities [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,576.5		2,208.5		2,016.2
Vertically Integrated Utilities [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,543.8	[1]	2,168.2		2,018
Vertically Integrated Utilities [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		212.2		170.6		155.6
Vertically Integrated Utilities [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,401.1		1,298.1		922.8
Vertically Integrated Utilities [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		958.3		942.6		588.3
Vertically Integrated Utilities [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		442.8	[2]	355.5	[3]	334.5	[4]
Vertically Integrated Utilities [Member] \| Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[5]	0	[6]
Vertically Integrated Utilities [Member] \| Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[7]	0	[8]
Vertically Integrated Utilities [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		241.1	[9]	187.5	[5]	163.2	[6]
Vertically Integrated Utilities [Member] \| Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		11,473.3		9,985.5		8,882.6
Vertically Integrated Utilities [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		4.2		13		(3.2)
Vertically Integrated Utilities [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		3.8	[10]	13.5	[11]	(3.2)	[12]
Vertically Integrated Utilities [Member] \| Other Revenues [Member]
Revenue, Performance Obligation
Revenues		0.4	[1],[13]	(0.5)	[5],[14]	0	[6],[15]
Transmission And Distribution Utilities [Member]
Revenue, Performance Obligation
Revenues		5,512		4,492.9		4,345.9
Revenue Textuals
Revenue from Related Parties		22.4		28.8		107.2
Transmission And Distribution Utilities [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		4,622.9		3,658.5		3,568.1
Transmission And Distribution Utilities [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,497.3		2,138.2		2,086.9
Transmission And Distribution Utilities [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,365.2		1,081.2		1,048.6
Transmission And Distribution Utilities [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		711.3	[1]	395.2		390.1
Transmission And Distribution Utilities [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		49.1		43.9		42.5
Transmission And Distribution Utilities [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		650		572.4		467
Transmission And Distribution Utilities [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Transmission And Distribution Utilities [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		650	[2]	572.4	[3]	467	[4]
Transmission And Distribution Utilities [Member] \| Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[5]	0	[6]
Transmission And Distribution Utilities [Member] \| Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[7]	0	[8]
Transmission And Distribution Utilities [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		247.3	[9]	194.2	[5]	157.8	[6]
Transmission And Distribution Utilities [Member] \| Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		5,520.2		4,425.1		4,192.9
Transmission And Distribution Utilities [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(8.2)		67.8		153
Transmission And Distribution Utilities [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(26.8)	[10]	48.8	[11]	70	[12]
Transmission And Distribution Utilities [Member] \| Other Revenues [Member]
Revenue, Performance Obligation
Revenues		18.6	[1],[13]	19	[5],[14]	83	[6],[15]
AEP Transmission Holdco [Member]
Revenue, Performance Obligation
Revenues		1,677		1,526.2		1,198.8
AEP Transmission Holdco [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Holdco [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Holdco [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Holdco [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0		0
AEP Transmission Holdco [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Holdco [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,700.6		1,456.4		1,257
AEP Transmission Holdco [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
AEP Transmission Holdco [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,700.6	[2]	1,456.4	[3]	1,257	[4]
Revenue Textuals
Revenue from Related Parties		1,300		1,100		965
AEP Transmission Holdco [Member] \| Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[5]	0	[6]
AEP Transmission Holdco [Member] \| Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[7]	0	[8]
AEP Transmission Holdco [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		8.2	[9]	17.1	[5]	22.4	[6]
AEP Transmission Holdco [Member] \| Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,708.8		1,473.5		1,279.4
AEP Transmission Holdco [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		(31.8)		52.7		(80.6)
AEP Transmission Holdco [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		(31.8)	[10]	52.7	[11]	(80.6)	[12]
AEP Transmission Holdco [Member] \| Other Revenues [Member]
Revenue, Performance Obligation
Revenues		0	[1],[13]	0	[5],[14]	0	[6],[15]
Generation and Marketing [Member]
Revenue, Performance Obligation
Revenues		2,466.9		2,163.7		1,725.6
Revenue Textuals
Revenue from Related Parties		18		55.4		104.6
Generation and Marketing [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Generation and Marketing [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Generation and Marketing [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Generation and Marketing [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0		0
Generation and Marketing [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Generation and Marketing [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,113.5		1,947.4		1,679.7
Generation and Marketing [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		271.2		137.9		131.9
Generation and Marketing [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[2]	0	[3]	0	[4]
Generation and Marketing [Member] \| Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		129.1	[1]	86.9	[5]	60.9	[6]
Generation and Marketing [Member] \| Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		1,713.2	[1]	1,722.6	[7]	1,486.9	[8]
Revenue Textuals
Revenue from Related Parties				52		103
Generation and Marketing [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		12.1	[9]	7.2	[5]	2.3	[6]
Generation and Marketing [Member] \| Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		2,125.6		1,954.6		1,682
Generation and Marketing [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		341.3		209.1		43.6
Generation and Marketing [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		0	[10]	0	[11]	0	[12]
Generation and Marketing [Member] \| Other Revenues [Member]
Revenue, Performance Obligation
Revenues		341.3	[1],[13]	209.1	[5],[14]	43.6	[6],[15]
Other Segments [Member]
Revenue, Performance Obligation
Revenues	[31]	109.9		72.2		96.8
Revenue Textuals
Revenue from Related Parties	[31]	59.2		55.9		88.6
Other Segments [Member] \| Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Other Segments [Member] \| Residential [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Other Segments [Member] \| Commercial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Other Segments [Member] \| Industrial [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0		0
Other Segments [Member] \| Other Retail [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Other Segments [Member] \| Wholesale and Competitive [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		6.9		1.4		(5.5)
Other Segments [Member] \| Wholesale Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0		0		0
Other Segments [Member] \| Wholesale Transmission [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[2]	0	[3]	0	[4]
Other Segments [Member] \| Renewable Generation [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		0	[1]	0	[5]	0	[6]
Other Segments [Member] \| Retail, Trading and Marketing Revenue [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		6.9	[1]	1.4	[7]	(5.5)	[8]
Other Segments [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		93.9	[9]	60.1	[5]	92.5	[6]
Other Segments [Member] \| Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers		100.8		61.5		87
Other Segments [Member] \| Alternative and Other [Member]
Revenue, Performance Obligation
Revenues		9.1		10.7		9.8
Other Segments [Member] \| Alternative [Member]
Revenue, Performance Obligation
Revenues		0	[10]	0	[11]	0	[12]
Other Segments [Member] \| Other Revenues [Member]
Disaggregation of Revenue
Revenue from Contracts with Customers	[31]	50.7		16.3		8.2
Revenue, Performance Obligation
Revenues		9.1	[1],[13]	$ 10.7	[5],[14]	$ 9.8	[6],[15]
Corporate and Other [Member] \| Other Revenues [Member]
Revenue Textuals
Revenue from Related Parties		$ 59

[1]Amounts include affiliated and nonaffiliated revenues.[2]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.3 billion. The remaining affiliated amounts were immaterial.[3]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.1 billion. The remaining affiliated amounts were immaterial.[4]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $965 million. The remaining affiliated amounts were 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 Generation & Marketing was $52 million. The remaining affiliated amounts were immaterial.[8]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $103 million. The remaining affiliated amounts were immaterial.[9]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $59 million. The remaining affiliated amounts were immaterial.[10]Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.[11]Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.[12]Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.[13]Generation & Marketing includes economic hedge activity.[14]Generation & Marketing includes economic hedge activity.[15]Generation & Marketing includes economic hedge activity.[16]Amounts include affiliated and nonaffiliated revenues.[17]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $170 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.[18]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.[19]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $112 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.[20]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.3 billion, APCo was $78 million and SWEPCo was $51 million. The remaining affiliated amounts were immaterial.[21]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.1 billion. The remaining affiliated amounts were immaterial.[22]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $952 million. The remaining affiliated amounts were immaterial.[23]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $62 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.[24]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $60 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.[25]Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $69 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.[26]Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.[27]Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.[28]Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.[29]Amounts include affiliated and nonaffiliated revenues.[30]Amounts include affiliated and nonaffiliated revenues.[31]Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in Carrying Amount of Goodwill
Goodwill	$ 52.5	$ 52.5	$ 52.5
Impairment Losses	0	0
Corporate and Other [Member]
Changes in Carrying Amount of Goodwill
Goodwill	37.1	37.1	37.1
Impairment Losses	0	0
Generation and Marketing [Member]
Changes in Carrying Amount of Goodwill
Goodwill	15.4	15.4	$ 15.4
Impairment Losses	$ 0	$ 0

Subsequent Events (Details)

Subsequent Events (Details) $ in Millions	12 Months Ended
Subsequent Events (Details) $ in Millions	Dec. 31, 2022 USD ($) GWh	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Equity Method Investment	$ 1,276.7	$ 1,447.5	$ 1,406.3
Equity Method Investment, Ownership Percentage	50%
Generation and Marketing [Member]
Equity Method Investment	$ 337.6	$ 487.8	$ 467
Competitive Contracted Renewables \| Generation and Marketing [Member]
Contracted Renewables GWs \| GWh	1.4
Competitive Contracted Renewables NBV	$ 1,200
Equity Method Investment	$ 247
Equity Method Investment, Ownership Percentage	50%
Subsequent Event [Member] \| Competitive Contracted Renewables \| Generation and Marketing [Member]
Enterprise Value	$ 1,500
Indemnification	70
Proceeds from Sales of Assets	1,200
Anticipated Pretax Loss Range Lower	175
Anticipated Pretax Loss Range Upper	225
Anticipated After Tax Loss Range Lower	100
Anticipated After Tax Loss Range Upper	$ 150